NATIONAL OILWELL VARCO INC
ITEM 1. BUSINESS
General
National Oilwell Varco, Inc. (“NOV” or the “Company”), a Delaware corporation incorporated in 1995, is a leading worldwide provider of equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry. The Company conducts operations in over 1,235 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.
On September 24, 2013, the Company announced that its Board of Directors authorized Company management to move forward with exploration of a plan to spin-off the Company’s distribution business from the remainder of the Company, creating two stand-alone, publicly traded corporations. The Company believes that the separation of the distribution business can be accomplished via a tax-efficient spin-off to Company shareholders.
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, training and service 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, valves, 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, processing plants, and industrial facilities 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. Each year 2011, 2012 and 2013 saw a further improvement in order rates as commodity prices remained at levels supporting sustained capital spending by our customers. However, the global rig count decreased 3% in 2013 compared to 2012 after rising by 1.5% in 2012 compared to 2011. Backlog for the Company was approximately $16.2 billion at December 31, 2013 compared to approximately $11.9 billion and $10.2 billion for December 31, 2012 and 2011, respectively.
In 2011, 2012 and 2013, 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. 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. Oil prices then recovered since 2009, and rose to $85 per barrel by the end of 2010. Oil prices remained flat in the $90-$100 per barrel range through 2012 and 2013. 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. During 2013, prices continued to rise and remained steady in the $3.00-$4.50 per mmbtu range ending the year over $4.00 per mmbtu.
Expectations for future oil and gas prices cause many shifts in the strategies and expenditure levels of oil and gas companies and drilling contractors, particularly with respect to decisions to purchase major capital equipment of the type we manufacture. Oil and gas prices, which are determined by the marketplace, may fall below a range that is acceptable to our customers, which could reduce demand for our products.
Worldwide financial and credit crisis could have a negative effect on our operating results and financial condition.
Events in 2008 and 2009 constrained credit markets and sparked a serious global banking crisis. The slowdown in worldwide economic activity caused by the global recession reduced demand for energy and resulted in lower oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition. Furthermore, many of our customers access the credit markets to finance their oil and natural gas drilling activity. If the recent crisis and recession reduce the availability of credit to our customers, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. Any such reduction in spending by our customers could adversely impact our operating results and financial condition.
There are risks associated with certain contracts for our drilling equipment.
As of December 31, 2013, we had a backlog of approximately $16.2 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 significant down payment and progress billing terms favorable to the ultimate completion of these projects and the majority do not allow customers to cancel projects for convenience. However, unfavorable market conditions or financial difficulties experienced by our customers may result in cancellation of contracts or the delay or abandonment of projects.
Any such developments could have a material adverse effect on our operating results and financial condition.
Competition in our industry could ultimately lead to lower revenues and earnings.
The oilfield products and services industry is highly competitive. We compete with national, regional and foreign competitors in each of our current major product lines. Certain of these competitors may have greater financial, technical, manufacturing and marketing resources than us, and may be in a better competitive position. The following competitive actions can each affect our revenues and earnings:
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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 65% of our revenues in 2013 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Canada, Europe, the Middle East, Africa, Southeast Asia, Latin America and other international markets. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which we operate have adopted policies, or are subject to governmental policies, giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of these policies, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationships between us and government-owned petroleum companies.
Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States or other governments or organizations. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission and other federal agencies and authorities have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt Practices Act and other federal statutes. Under trading sanctions laws, the DOJ may seek to impose modifications to business practices, including cessation of business activities in sanctioned countries, and modifications to compliance programs, which may increase compliance costs. If any of the risks described above materialize, it could adversely impact our operating results and financial condition.
We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.
The results of our operations are subject to market risk from changes in foreign currency exchange rates.
We earn revenues, pay expenses, purchase assets and incur liabilities in countries using currencies other than the U.S. dollar, including, but not limited to, the Canadian dollar, the Euro, the British pound sterling, the Norwegian krone and the South Korean won. Approximately 65% of our 2013 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 $4,537 million (with a fair value of a net asset of $19 million) as of December 31, 2013, 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 $9.0 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives as of December 31, 2013. 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 approximately 10% of total revenue from one of our customers during the years ended December 31, 2013, 2012 and 2011.
The loss of this customer (Samsung Heavy Industries) or a significant reduction in its purchases could adversely affect our future revenues and earnings. Samsung Heavy Industries is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.
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.
Risks associated with the separation of our distribution business.
Our planned separation of our distribution business, under the name NOW Inc., is subject to a number of risks, including the following:
Risk of Non-Consummation. Although we expect to distribute 100% of the shares of NOW Inc. common stock to NOV stockholders in the first half of 2014, the distribution remains subject to various conditions, including, but not limited to: (i) the SEC having declared effective NOW Inc.’s registration statement on Form 10 and (ii) the receipt of tax opinions to the effect that the distribution, together with certain related transactions, will qualify as tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”). There can be no assurance that any or all of the conditions will be met and that the distribution will be completed in the manner currently contemplated, or at all. In addition, the fulfillment of the conditions does not create any obligations on our part to effect the distribution, and our board of directors has reserved the right, in its sole discretion, to abandon, modify, or change the terms of the distribution.
Risks of Not Obtaining Benefits from the Separation. NOV and NOW Inc. may not realize some or all of the benefits we expect from the separation in the time frame currently contemplated, or at all.
Risks Relating to Less Diversification. If the distribution is completed, our diversification of revenue sources will diminish due to the separation of NOW Inc. from our other businesses, and it is possible that our results of operations, cash flows, working capital and financing requirements may be subject to increased volatility as a result.
Risks Relating to Taxes. The IRS no longer issues private letter rulings regarding whether or not a spin-off transaction qualifies for tax-free treatment under Section 355 of the Code. Notwithstanding the tax opinions we are to receive from our legal and tax advisors that the distribution of 100% of the shares of NOW Inc. common stock will qualify as tax-free under such section of the Code, the IRS could determine on audit that the distribution should be treated as a taxable transaction, including as a result of a significant change in stock or asset ownership after the distribution. If the distribution ultimately is determined to be taxable, we and/or our stockholders that are subject to U.S. federal income tax could incur significant U.S. federal income tax liabilities.
GLOSSARY OF OILFIELD TERMS
(Sources: Company management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)
API
Abbr: American Petroleum Institute
Annular Blowout Preventer
A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.
Annulus
The open space around pipe in a wellbore through which fluids may pass.
Automatic Pipe Handling
Systems (Automatic Pipe
Racker)
A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.
Automatic Roughneck
A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.
Beam pump
Surface pump that raise and lowers sucker rods continually, so as to operate a downhole pump.
Bit
The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (“PDCs”). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.
Blowout
An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.
Blowout Preventer (BOP)
Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
Blowout Preventer (BOP) Stack
The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
Closed Loop Drilling Systems
A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.
Coiled Tubing
A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a reel, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.
Cuttings
Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.
Directional Well
Well drilled in an orientation other than vertical in order to access broader portions of the formation.
Drawworks
The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.
Drill Pipe Elevator (Elevator)
On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.
Drilling jars
A percussion tool operated manually or hydraulically to deliver a heavy downward blow to free a stuck drill stem.
Drilling mud
A specially compounded liquid circulated through the wellbore during rotary drilling operations.
Drilling riser
A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.
Drill stem
All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.
Fiberglass-reinforced
spoolable pipe
A spoolable glass fiber-reinforced epoxy composite tubular product for onshore oil and gas gathering and injection systems, with superior corrosion resistant properties and lower installed cost than steel.
Flexible pipe
A dynamic riser that connects subsea production equipment to a topside facility allowing for the flow of oil, gas, and/or water.
Formation
A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
FPSO
A Floating Production, Storage and Offloading vessel used to receive hydrocarbons from subsea wells, and then produce and store the hydrocarbons until they can be offloaded to a tanker or pipeline.
Hardbanding
A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.
Hydraulic Fracturing
The process of creating fractures in a formation by pumping fluids, at high pressures, into the reservoir, which allows or enhances the flow of hydrocarbons.
Iron Roughneck
A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.
Jack-up rig
A mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.
Jar
A mechanical device placed near the top of the drill stem which allows the driller to strike a very heavy blow upward or downward on stuck pipe.
Joint
1. In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 meters, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2. In pipelining, a single length (usually 40 feet-12 meters) of pipe. 3. In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.
Kelly
The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 meters) long, and have diameters as small as 2.5 inches (6 centimeters) and as large as 6 inches (15 centimeters).
Kelly bushing
A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.
Kelly spinner
A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.
Kick
An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.
Making-up
1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).
Manual tongs (Tongs)
The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.
Master bushing
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.
Mooring system
The method by which a vessel or buoy is fixed to a certain position, whether permanently or temporarily.
Motion compensation
equipment
Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.
Mud pump
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig.
Plug gauging
The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.
Pressure control equipment
Equipment used in: 1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.
Pressure pumping
Pumping fluids into a well by applying pressure at the surface.
Ram blowout preventer
A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.
Ring gauging
The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.
Riser
A pipe through which liquids travel upward.
Riser pipe
The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.
Rotary table
The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.
Rotating blowout
preventer (Rotating Head)
A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.
Safety clamps
A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.
Shaker
See “Shale Shaker”
Shale shaker
A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.
Slim-hole completions
(Slim-hole Drilling)
Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
Slips
Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.
Solids
See “Cuttings”
Spinning wrench
Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
Spinning-in
The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.
Stand
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
String
The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.
Sucker rod
A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.
Tensioner
A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.
Thermal desorption
The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.
Tiebacks (Subsea)
A series of flowlines and pipes that connect numerous subsea wellheads to a single collection point.
Top drive
A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.
Torque wrench
Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.
Trouble cost
Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
Turret
Mechanical device that allows a floating vessel to rotate around stationary flowlines, umbilicals, and other associated risers.
Well completion
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
Wellhead
The termination point of a wellbore at surface level or subsea, often incorporating various valves and control instruments.
Well stimulation
Any of several operations used to increase the production of a well, such as acidizing or fracturing.
Well workover
The performance of one or more of a variety of remedial operations on a producing oil well to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.
Wellbore
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Wireline
A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The Company owned or leased over 1,235 facilities worldwide as of December 31, 2013, including the following principal manufacturing, service, distribution and administrative facilities:
* Building owned but land leased.
We own or lease more than 185 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, approximately 450 distribution service centers and 600 service centers that provide inspection and equipment rental worldwide.
ITEM 3. LEGAL PROCEEDINGS
We have various claims, lawsuits and administrative proceedings that are pending or threatened, all arising in the ordinary course of business, with respect to commercial, product liability and employee matters. Although no assurance can be given with respect to the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits or administrative proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. See Note 12 to the Consolidated Financial Statements.
ITEM 4. MINE SAFETY DISCLOSURES
Information regarding mine safety and other regulatory actions at our mines is included in Exhibit 95 to this Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock is traded on the New York Stock Exchange (NYSE) under the symbol “NOV”. The following table sets forth, for the calendar periods indicated, the range of high and low closing prices for the common stock, as reported by the NYSE and the cash dividends declared per share.
As of February 7, 2014, there were 3,106 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 $389 million and $209 million for the years ended December 31, 2013 and 2012, 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, 2008 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. SELECTED FINANCIAL DATA
(1) Financial information for prior periods and dates may not be comparable due to the impact of $2.4 billion in business combinations on our financial position and results of operations during 2013.
(2) Financial information for prior periods and dates may not be comparable due to the impact of $2.9 billion in business combinations on our financial position and results of operations during 2012.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General Overview
The Company is a leading worldwide provider of highly engineered drilling and well-servicing equipment, products and services to the exploration and production segments of the oil and gas industry. With operations in over 1,235 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 nonrecurring items, operating profit percentage excluding nonrecurring items and diluted earnings per share excluding nonrecurring items, 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, 2013 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 $97.91 per barrel in 2013, an increase of 4% over the average price for 2012 of $94.11 per barrel. The average natural gas price was $3.72 per mmbtu, an increase of 35% compared to the 2012 average of $2.75 per mmbtu. Average rig activity worldwide decreased 3% for the full year in 2013 compared to 2012. The average crude oil price for the fourth quarter of 2013 was $97.34 per barrel and natural gas was $3.84 per mmbtu.
At February 7, 2014, there were 2,392 rigs actively drilling in North America, compared to 2,020 rigs at December 31, 2013; an increase of 18.4% from year end 2013 levels. The price of oil increased to $99.98 per barrel and gas increased to $4.78 per mmbtu at February 7, 2014, representing a 1.8% increase in oil prices and an 11.9% increase in gas prices from the end of 2013.
EXECUTIVE SUMMARY
During 2013 National Oilwell Varco, Inc. earned $2.3 billion in net income attributable to Company, or $5.44 per fully diluted share. Earnings per diluted share decreased 7% from prior year levels of $2.5 billion or $5.83 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 $5.52 in 2013 decreased 7% from $5.91 per share in 2012.
During 2013 revenue grew 14% from 2012, to $22.9 billion, and operating profit declined 4% from 2012, to $3.4 billion. Generally, 2013 benefitted from the acquisition of Robbins & Myers as well as higher international drilling activity, which saw international rig counts (as measured by Baker Hughes) increase 5% from 2012. 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, 2013, the Company generated $658 million in net income attributable to Company, or $1.53 per fully diluted share, on $6.2 billion in revenue. Compared to the third quarter of 2013 revenue increased $485 million or 9% and net income attributable to Company increased $22 million. Compared to the fourth quarter of 2012, revenue increased $487 million or 9%, and net income attributable to Company decreased $10 million or 1%.
The fourth quarter of 2013 included pre-tax other costs of $16 million, the third quarter of 2013 included pre-tax other costs of $10 million and a pre-tax gain of $102 million resulting from the settlement of a legal claim, and the fourth quarter of 2012 included pre-tax other costs of $51 million, and a net $69 million tax benefit related to certain U.S. foreign tax credits in the quarter. Excluding the pre-tax gain, tax benefit and other costs from all periods, fourth quarter 2013 earnings were $1.56 per fully diluted share, compared to $1.34 per fully diluted share in the third quarter of 2013 and $1.49 per fully diluted share in the fourth quarter of 2012.
Operating profit excluding other costs and the litigation gains was $973 million or 15.8% of sales in the fourth quarter of 2013, compared to $853 million or 14.7% of sales in the third quarter of 2013, and $954 million or 16.8% of sales in the fourth quarter of 2012.
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 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. In the fourth quarter 2012, gas prices recovered to average $3.40 per mmbtu; and, for the full year 2013, gas prices averaged $3.72 per mmbtu. The 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 for the fourth quarter of 2012. The average U.S. rig count declined to 1,758 rigs in the first quarter of 2013, and remained relatively flat throughout the year. 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 58% from the fourth quarter of 2011, to an average of 371 in the fourth quarter of 2013. However, with high oil prices, many have redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. For the fourth quarter of 2013, oil-directed drilling rose to almost 78% of the total domestic drilling effort, and 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 average 1,321 rigs in the fourth quarter of 2013.
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 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 62% of the existing 513 jackup rigs are greater 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 2013 at a record $16.2 billion. Approximately $8.5 billion of these orders are scheduled to flow out as revenue during 2014, with the balance flowing out in 2015 and beyond. Of this backlog, 93% of the total is for equipment destined for offshore operations, with 7% destined for land. Equipment destined for international markets totaled 94% of the backlog.
Segment Performance
The Rig Technology segment generated $11.7 billion in revenues and $2.5 billion in operating profit or 21.5% of sales during 2013. Compared to the prior year, revenues improved 16% while operating profit dollars increased 8% year-over-year. For the fourth quarter of 2013, the segment generated $3.3 billion in revenues and $692 million in operating profit or 20.9% of sales. Compared to the prior quarter, revenues increased $365 million or 12%, and operating profit decreased $14 million. Compared to the fourth quarter of 2012, segment revenues grew $414 million or 14%, and operating profit increased $56 million. Year-over-year operating leverage or flow-through was 14%. 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 20% sequentially and increased 14% year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased 7% sequentially and increased 15% from the fourth quarter of 2012. Orders for four deepwater floating rig equipment packages, and twenty five drilling equipment packages for jackup rigs, contributed to total order additions to backlog of $3.6 billion during the fourth quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs remain strong, rig building costs have stabilized at attractive levels, and financing appears to be available for most established drillers. The segment also benefitted from the shipment of several land rigs in the fourth quarter; and, despite the continued decline in demand for pressure pumping equipment in North America, the segment’s well intervention and stimulation product sales increased 11% sequentially, as unexpected demand in the quarter was filled with existing inventory.
The Petroleum Services & Supplies segment generated $7.2 billion in revenue and $1.2 billion in operating profit, or 16.9% of sales, for the full year 2013. Compared to the prior year, revenue increased 3%, but operating profit declined $289 million, as the 8% year-over-year reduction in the U.S. drilling rig count (as measured by Baker Hughes) led to pricing pressures and under-absorption in a number of the segment’s manufacturing and service facilities. For the fourth quarter of 2013, the segment generated $1.9 billion in revenue and $363 million in operating profit, or 18.9% of sales. Compared to the prior quarter, revenue increased $116 million or 6%, and operating profit increased $42 million, representing 36% incremental operating leverage. Sequentially, drilling and completions activities in Canada continued to improve following the annual seasonal slow-down known as “break-up”. This increase in activity created slight incremental demand for the segment’s products and services, which generated 1% sequential growth for the segment in Canada. In the U.S., a relatively flat rig count, combined with fewer billing days in the quarter due to holidays, led to a 3% sequential decline. Demand in the U.S. for drill pipe and downhole tools remained muted in the quarter due to a still over-supplied U.S. land drilling and well-service market. Internationally, driven by some large year-end project shipments, revenues for the segment increased 18%. Compared to the fourth quarter of 2012, revenues increased $155 million, and operating profit increased $23 million, as both pricing pressures and under-absorbed facilities continue to pressure margins. For the fourth quarter of 2013, approximately 51% of the segment’s sales were into North American markets, and 49% of sales were into international markets.
The Distribution & Transmission segment generated $5.1 billion in revenue and $247 million in operating profit or 4.8% of sales during 2013. Revenues improved 30% from 2012, primarily due to the acquisitions of Wilson during the second quarter of 2012 and CE Franklin during the third quarter of 2012. For the fourth quarter of 2013, the segment generated $1.3 billion in revenue and $60 million in operating profit or 4.8% of sales. Revenues declined $89 million or 7% from the third quarter of 2013, and operating profit decreased $18 million. Compared to the fourth quarter of 2012, revenues decreased $15 million or 1% and operating profit decreased $18 million. Sequentially, revenues declined 8% in the U.S., as the holidays and severe weather disruptions led to fewer billing days in the fourth quarter. Additionally, the segment was challenged as some large project sales into international markets in the third quarter did not repeat in the fourth quarter. The fourth quarter 2013 year-over-year revenue decline is directly attributable to the decline in the U.S. rig count over that same period. For the fourth quarter of 2013, approximately 81% of the group’s sales were into North American markets and 19% 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 remain at high levels. Still, margins, which were 20.9% in the fourth quarter of 2013, may continue to be challenged to expand beyond current levels 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, low gas and natural gas liquids prices, higher costs of execution due to significantly compressed project timelines, continued flow through of lower priced projects, and 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 U.S. rig counts relatively unchanged from the prior quarter, resulting in an average U.S. rig count in the fourth quarter that was down 3% from the average U.S. rig count in the fourth quarter of 2012. The fourth quarter saw average Canadian rig counts improve almost 9% sequentially and almost 3% year-over-year. As a result, revenues for both segments improved sequentially in Canada; however, for both the U.S. and Canada, pricing and volumes remain under pressure as pressure pumpers, drilling contractors and oil companies continue to carefully scrutinize 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. 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, 2013 and December 31, 2012
The following table summarizes the Company’s revenue and operating profit by operating segment in 2013 and 2012 (in millions):
Rig Technology
Revenue from Rig Technology for the year ended December 31, 2013 was $11,716 million, an increase of $1,609 million (15.9%) compared to the year ended December 31, 2012. Deepwater offshore demand as well as demand in international markets continues to be a driving force for the increase in revenue for Rig Technology as revenue out of backlog contributed $8,740 million in 2013. Increased sales of individual capital components, a continued increase in activity in the Company’s aftermarket and FPSO businesses as well as the acquisition of Robbins & Myers all contributed to the increase in revenue for Rig Technology. In addition, a nonrecurring gain of $102 million was recognized in the third quarter of 2013 related to a legal settlement. North American markets continue to see a decrease in demand for land drilling equipment. This is evidenced by a decrease in rig count in North America from 2012 and has resulted in a steady decline in sales of land rigs and pressure pumping equipment in the U.S. and Canada. The average rig count in the U.S. for the year ended 2013 decreased over 8% compared to the year ended 2012 and decreased 3% in Canada over the same period.
Operating profit from Rig Technology was $2,522 million for the year ended December 31, 2013, an increase of $187 million (8.0%) compared to 2012. Operating profit percentage decreased to 21.5%, from 23.1% in 2012. The decrease in operating profit percentage continues to be primarily due to a shift in product mix as lower priced offshore projects replace projects contracted at higher prices in 2007 and 2008. FPSO revenue continues to increase with operating margins that are dilutive while land rig and pressure pumping equipment revenue, with margins that are generally accretive, continues to decline. In addition, our shipyard customers are compressing delivery schedules which have been leading to increased freight and personnel costs. Expenses associated with acquisition integration efforts, numerous strategic growth initiatives and capacity expansions worldwide have also contributed to the decrease in operating profit percentage.
Included in operating profit are certain other costs which include items such as transaction costs and the amortization of backlog and inventory that was stepped up during purchase accounting. Other costs included in operating profit for Rig Technology were $27 million for the year ended December 31, 2013 and $45 million for the year ended December 31, 2012.
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 $16.2 billion at December 31, 2013, an increase of $4.4 billion (37.0%) from backlog of $11.9 billion at December 31, 2012. At December 31, 2013, approximately 93% of the capital equipment backlog was for offshore products and 7% was for land; and approximately 94% of the capital equipment backlog was for international markets and 6% was for domestic markets.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies for the year ended December 31, 2013 was $7,184 million, an increase of $217 million (3.1%) compared to the year ended December 31, 2012. The increase is primarily due to the acquisition of Robbins & Myers during the first quarter of 2013 as well as increased activity internationally as evidenced by the 5% increase in the international rig count in 2013 compared to 2012. These increases were offset to some extent by lower North American drilling activity. Approximately 54% of 2013 revenue for this segment was derived from North American markets and 46% from international markets.
Operating profit from Petroleum Services & Supplies was $1,212 million for the year ended December 31, 2013 compared to $1,501 million for 2012, an decrease of $289 million (19.3%). Operating profit percentage decreased to 16.9% from 21.5% in 2012. This decrease is primarily due to the overall decline in North American market activity which has led to pricing pressures across a number of products in the North American land market, as well as volume declines. Expenses associated with integrating recently acquired companies also contributed to the decrease in operating profit percentages.
Included in operating profit are certain other costs which include items such as transaction costs and the amortization of inventory that was stepped up during purchase accounting. Other costs included in operating profit for Petroleum Services & Supplies were $93 million for the year ended December 31, 2013 and $18 million for the year ended December 31, 2012.
Distribution & Transmission
Revenue from Distribution & Transmission was $ 5,117 million for the year ended December 31, 2013, an increase of $ 1,190 million (30.3%) compared to the year ended December 31, 2012. This increase was primarily attributable to the acquisition of Robbins & Myers during the first quarter of 2013, Wilson during the second quarter of 2012 and CE Franklin during the third quarter of 2012. The increase related to these acquisitions was offset to some extent by lower North American drilling activity. Of the 2013 revenue for the segment, approximately 81% was derived from North American markets and 19% from international markets.
Operating profit from Distribution & Transmission was $247 million for the year ended December 31, 2013, an increase of $62 million (33.5%) compared to $185 million for the year ended December 31, 2012. Operating profit percentage increased to 4.8%, from 4.7% in 2012. This increase is attributable to the increased activity in both Canada and International markets, and the inclusion of other costs related to purchase accounting which is lower in 2013 as compared to 2012. Slightly offsetting the increase is the continued lower overall market activity in the U.S.
Included in operating profit are certain other costs which include items such as transaction costs and the amortization of inventory that was stepped up during purchase accounting. Other costs included in operating profit for Distribution & Transmission were $27 million for the year ended December 31, 2013 and $68 million for the year ended December 31, 2012.
Unallocated expenses and eliminations
Unallocated expenses and eliminations in operating profit were $558 million for the year ended December 31, 2013 compared to $464 million for the year ended December 31, 2012. This increase was primarily due to increased intercompany sales activity for all segments resulting in higher intersegment eliminations.
Interest and financial costs
Interest and financial costs were $111 million for the year ended December 31, 2013 compared to $49 million for the year ended December 31, 2012. This increase is primarily due to an overall increase in average debt during 2013 compared 2012.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $63 million for the year ended December 31, 2013 compared to $58 million for the year ended December 31, 2012. This increase was primarily due to increased equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.
Other income (expense), net
Other income (expense), net were expenses of $41 million for the year ended December 31, 2013 compared to expenses of $71 million for the year ended December 31, 2012. The change was primarily due to gains on the sale of certain assets during the second quarter of 2013, offset by foreign exchange losses and increased bank charges and fees.
Provision for income taxes
The effective tax rate for the year ended December 31, 2013 was 30.4%, compared to 29.2% for 2012. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of lower tax rates on income earned in foreign jurisdictions, that is considered to be permanently reinvested, a reduced tax rate in the UK and Norway, and the deduction in the U.S. for manufacturing activities. The effective tax rate was negatively impacted by foreign dividends net of foreign tax credits, foreign exchange gains for tax reporting in Norway, and the recognition of increased valuation allowances on certain deferred tax assets associated with excess foreign tax credits carried to future periods.
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.
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 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 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.
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 a 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.
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 tubing, and fluid end expendables products. While decline 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.
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.
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 amortized by December 31, 2012.
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, that is considered to be permanently reinvested, 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.
Non-GAAP Financial Measures and Reconciliations
In an effort to provide investors with additional information regarding our results as determined by GAAP, we disclose various non-GAAP financial measures in our quarterly earnings press releases and other public disclosures. The primary non-GAAP financial measures we focus on are: (i) operating profit excluding nonrecurring items, (ii) operating profit percentage excluding nonrecurring items, and (iii) diluted earnings per share excluding nonrecurring items. Each of these financial measures excludes the impact of certain nonrecurring items and therefore has not been calculated in accordance with GAAP. A reconciliation of each of these non-GAAP financial measures to its most comparable GAAP financial measure is included below.
We use these non-GAAP financial measures internally to evaluate and manage the Company’s operations because we believe it provides useful supplemental information regarding the Company’s on-going economic performance. We have chosen to provide this information to investors to enable them to perform more meaningful comparisons of operating results and as a means to emphasize the results of on-going operations.
The following tables set forth the reconciliations of these non-GAAP financial measures to their most comparable GAAP financial measures (in millions, except per share data):
(1) Included in Rig Technology revenue and operating profit for the three months ended September 30, 2013 and for the year ended December 31, 2013, is a $102 million gain resulting from a legal settlement.
(2) Other costs primarily include items such as transaction costs and the amortization of backlog and inventory that was stepped up to fair value during purchase accounting, items which are included in operating profit. For the three months and for the year ended December 31, 2013, other costs included in operating profit were $16 million and $147 million, respectively. For the three months and for the year ended December, 2012, other costs included in operating profit were $51 million and $131 million, respectively. Other costs for the three months ended September 30, 2013 totaled $9 million. Certain other costs that are included in other income(expense), net were nil and $9 million for the three months and for the year ended December 31, 2013, respectively; $9 million and $12 million for the three months and for the year ended December 31, 2012, respectively; and $1 million for the three months ended September, 2013.
(3) Includes a net $69 million tax benefit related to certain U.S. foreign tax credits arising in the three months ended December 31, 2012. These credits resulted from a strategic reorganization of certain foreign operations to more fully integrate recently acquired businesses.
Liquidity and Capital Resources
The Company assesses liquidity in terms of its ability to generate cash to fund operating, investing and financing activities. The Company remains in a strong financial position, with resources available to reinvest in existing businesses, strategic acquisitions and capital expenditures to meet short- and long-term objectives. The Company believes that cash on hand, cash generated from expected results of operations and amounts available under its revolving credit facility will be sufficient to fund operations, anticipated working capital needs and other cash requirements including capital expenditures, debt and interest payments and dividend payments for the foreseeable future.
At December 31, 2013, the Company had cash and cash equivalents of $3,436 million, and total debt of $3,150 million. At December 31, 2012, cash and cash equivalents were $3,319 million and total debt was $3,149 million. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Of the $3,436 million of cash and cash equivalents at December 31, 2013, approximately $3,102 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, the Company may choose to borrow against its $3.5 billion revolving credit facility. In August 2013, the Company initiated a commercial paper program, supported by its revolving credit facility.
The Company’s outstanding debt at December 31, 2013 was $3,150 million and consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,396 million in 2.60% Senior Notes, $1,096 million in 3.95% Senior Notes, and other debt of $7 million.
At December 31, 2013, there were $947 million in outstanding letters of credit issued, resulting in $2,553 million of funds available under the Company’s revolving credit facility.
The Company also had $3,056 million of additional outstanding letters of credit at December 31, 2013, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advance payment bonds and performance bonds.
The following table summarizes our net cash provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the periods presented (in millions):
Operating Activities
2013 vs 2012. Net cash provided by operating activities was $3,397 million in 2013 compared to net cash provided by operating activities of $620 million in 2012. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $2,328 million plus non-cash charges of $422 million and $66 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $63 million in equity income. Net changes in operating assets and liabilities, net of acquisitions, provided $488 million in 2013 compared to $2,536 million used in 2012. This shift was primarily the result of increased cash collections in 2013, as prepayments and milestone invoicing outpaced costs incurred on projects. Further, greater fourth quarter 2013 equipment and product sales combined with improved inventory management led to a $396 million inventory reduction in 2013. Cash tax payments in 2013 were also down compared to 2012.
2012 vs 2011. Net cash provided by operating activities was $620 million in 2012 compared to net cash provided by operating activities of $2,143 million in 2011. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $2,483 million plus non-cash charges of $628 million and $61 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $58 million in equity income. Net changes in operating assets and liabilities, net of acquisitions, used $2,536 million in 2012 compared to $164 million used in 2011. Due to an increase in market activity during 2012 compared to 2011, revenue and backlog increased which is reflected in increased accounts receivable as well as a buildup in inventory. Increased market activity during 2012 also resulted in higher taxes paid, higher accounts payable and an increase in both costs in excess of billings and billings in excess of costs with costs incurred on major rig projects outpacing customer progress and milestone invoicing.
Investing Activities
2013 vs 2012. Net cash used in investing activities was $2,964 million in 2013 compared to net cash used in investing activities of $3,428 million in 2012. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures. The Company used approximately $2.5 billion for the purpose of acquiring Robbins & Myers during the first quarter of 2013. For the acquisition of Robbins & Myers, the Company borrowed approximately $1.4 billion under the $3.5 billion revolving credit facility and used approximately $1.1 billion of cash on hand to fund the acquisition. By the end of 2013, the Company repaid all of $1.4 billion initially borrowed under its revolving credit facility. Due to the continued growth in the Company worldwide both organically and through acquisitions, the Company used $669 million during 2013 for capital expenditures compared to $583 million for 2012.
2012 vs 2011. Net cash used in investing activities was $3,428 million in 2012 compared to net cash used in investing activities of $1,458 million in 2011. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures both of which increased in 2012 compared to 2011. The Company used $2,880 million for the purpose of strategic acquisitions during 2012 compared to $1,038 million in 2011. In addition, due to the continued growth in the Company worldwide, both organically and through acquisition, the Company used $583 million during 2012 for capital expenditures compared to $483 million in 2011. During 2012, the Company used a combination of its cash on hand, borrowings from its revolving credit facility and the issuance of Senior Notes to fund its acquisitions and capital expenditures.
Financing Activities
2013 vs 2012. Net cash used in financing activities was $305 million in 2013 shifting from net cash provided by financing activities of $2,583 million in 2012. The change was primarily due to a decrease in net borrowings during 2013 and the Company receiving lower proceeds from stock options exercised compared to 2012. In addition, the Company doubled its quarterly dividend beginning in the second quarter of 2013.
2012 vs 2011. Net cash provided by financing activities was $2,583 million in 2012 compared to net cash used in financing activities of $464 million in 2011. The change related to a shift from the Company primarily repaying debt during 2011 to the Company refinancing its revolving credit facility, expanding it to $3.5 billion, and issuing three truanches of Senior Notes for a total of $3.0 billion in Senior Notes during 2012. Funds received as a result of borrowing in 2012 were used to finance working capital and acquisitions and to make tax payments. Proceeds from stock options exercised increased to $113 million during the year ended December 31, 2012 compared to $96 million for the year ended December 31, 2011. The Company again increased its dividend to $209 million during the year ended December 31, 2012 compared to $191 million for the year ended December 31, 2011.
Other
The effect of the change in exchange rates on cash flows was a decrease of $11 million, an increase of $9 million and a decrease of $19 million for the years ended December 31, 2013, 2012 and 2011, respectively.
We believe that cash on hand, cash generated from operations and amounts available under our credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements, dividends and financing obligations.
We intend to pursue additional acquisition candidates, but the timing, size or success of any acquisition effort and the related potential capital commitments cannot be predicted. We continue to expect to fund future cash acquisitions primarily with cash flow from operations and borrowings, including the unborrowed portion of the revolving credit facility or new debt issuances, but may also issue additional equity either directly or in connection with acquisitions. There can be no assurance that additional financing for acquisitions will be available at terms acceptable to us.
A summary of the Company’s outstanding contractual obligations at December 31, 2013 is as follows (in millions):
As of December 31, 2013, the Company entered into two capital lease agreements each covering a period of 25 years, totaling approximately $490 million. The first lease becomes effective in 2014 and the second in 2016.
As of December 31, 2013, the Company had $127 million of unrecognized tax benefits. This represents the tax benefits associated with various tax positions taken, or expected to be taken, on domestic and international tax returns that have not been recognized in our financial statements due to uncertainty regarding their resolution. Due to the uncertainty of the timing of future cash flows associated with these unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 14 to the Consolidated Financial Statements included in this Report.
Critical Accounting Policies and Estimates
In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets; purchase price allocation of acquisitions; service and product warranties and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.
Revenue Recognition under Long-term Construction Contracts
The Company uses the percentage-of-completion method to account for certain long-term construction contracts in the Rig 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 to complete estimates at the beginning of each project, taking into account all factors considered likely to affect gross margin. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors as mentioned in “Risk Factors.” These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings.
Historically, the Company’s estimates have been reasonably dependable regarding the recognition of revenues and gross profits on percentage-of-completion contracts. Based upon an analysis of percentage-of-completion contracts for all open contracts outstanding at December 31, 2012 and 2011 adjustments (representing the differences between the estimated and actual results) to all outstanding contracts resulted in net decreases to gross profit margins of 0.69% ($58 million on $8.4 billion of outstanding contracts) and 0.78% ($78 million on $9.6 billion of outstanding contracts) for the years ended December 31, 2013 and 2012, respectively. While the Company believes that its estimates on outstanding contracts at and in future periods will continue to be reasonably dependable under percentage-of-completion accounting, the factors identified in the preceding paragraph could result in significant adjustments in future periods. The Company has recorded revenue on outstanding contracts (on a contract-to-date basis) of $11 billion at December 31, 2013.
Allowance for Doubtful Accounts
The determination of the collectability of amounts due from customer accounts requires the Company to make judgments regarding future events and trends. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer basis taking into account current market conditions and trends. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers. A substantial portion of the Company’s revenues come from international oil companies, international shipyards, international oilfield service companies, and government-owned or government-controlled oil companies. Therefore, the Company has significant receivables in many foreign jurisdictions. If worldwide oil and gas drilling activity or changes in economic conditions in foreign jurisdictions deteriorate, the creditworthiness of the Company’s customers could also deteriorate and they may be unable to pay these receivables, and additional allowances could be required. At December 31, 2013 and 2012, allowance for bad debts totaled $132 million and $120 million, or 2.6% and 2.7% of gross accounts receivable, respectively.
Historically, the Company’s charge-offs and provisions for the allowance for doubtful accounts have been immaterial to the Company’s consolidated financial statements. However, because of the risk factors mentioned above, changes in estimates could become material in future periods.
Inventory Reserves
Inventory is carried at the lower of cost or estimated net realizable value. The Company determines reserves for inventory based on historical usage of inventory on-hand, assumptions about future demand and market conditions, and estimates about potential alternative uses, which are usually limited. The Company’s inventory consists of specialized spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s large installed base of specialized equipment used throughout the oilfield. Customers rely on the Company to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The Company’s estimated carrying value of inventory therefore depends upon demand driven by oil and gas drilling and well remediation activity, which depends in turn upon oil and gas prices, the general outlook for economic growth worldwide, available financing for the Company’s customers, political stability in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. At December 31, 2013 and 2012, inventory reserves totaled $396 million and $338 million, or 6.6% and 5.4% of gross inventory, respectively.
While inventory reserves and accruals have not had a material impact on the Company’s financial results for the periods covered in this report, changes in worldwide oil and gas activity, or the development of new technologies which make older drilling technologies obsolete, could require the Company to record additional allowances to reduce the value of its inventory. Such changes in our estimates could be material under weaker market conditions or outlook.
Impairment of Long-Lived Assets (Excluding Goodwill and Other Indefinite-Lived Intangible Assets)
Long-lived assets, which include property, plant and equipment and identified intangible assets, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and estimated useful lives.
The carrying values of these assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. We estimate the fair value of these intangible and fixed assets using an income approach. This requires the Company to make long-term forecasts of its future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s products and services, future market conditions and technological developments. The forecasts are dependent upon assumptions regarding oil and gas prices, the general outlook for economic growth worldwide, available financing for the Company’s customers, political stability in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. The financial and credit market volatility directly impacts our fair value measurement through our income forecast as well as our weighted-average cost of capital, both key assumptions used in our calculation. Changes to these assumptions, including, but not limited to: sustained declines in worldwide rig counts below current analysts’ forecasts, collapse of spot and futures prices for oil and gas, significant deterioration of external financing for our customers, higher risk premiums or higher cost of equity, or any other significant adverse economic news could require a provision for impairment in a future period.
Goodwill and Other Indefinite-Lived Intangible Assets
The Company has approximately $9.0 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives as of December 31, 2013. Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that goodwill or other indefinite-lived intangible assets might be impaired. Events or circumstances which could indicate a potential impairment include, but not limited to: further sustained declines in worldwide rig counts below current analysts’ forecasts, further collapse of spot and futures prices for oil and gas, significant additional deterioration of external financing for our customers, higher risk premiums or higher cost of equity.
The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Fair value of the reporting units is determined in accordance with ASC Topic 820 “Fair Value Measurements and Disclosures” using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations, where possible.
The discounted cash flow is based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in measuring goodwill impairment, which bear the risk of change and could impact the Company’s goodwill impairment analysis, include the cash flow from operations from each of the Company’s individual business units and the weighted average cost of capital. The starting point for each of the reporting unit’s cash flow from operations is the detailed annual plan or updated forecast. The detailed planning and forecasting process takes into consideration a multitude of factors
including worldwide rig activity, inflationary forces, pricing strategies, customer analysis, operational issues, competitor analysis, capital spending requirements, working capital needs, customer needs to replace aging equipment, increased complexity of drilling, new technology, and existing backlog among other items which impact the individual reporting unit projections. Cash flows beyond the specific operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short-term or long-term trend.
The annual impairment test is performed during the fourth quarter of each year. The valuation techniques used in the annual test were consistent with those used during previous testing. The inputs used in the annual test were updated for current market conditions and forecasts. During the review of its 2013 annual impairment test, the calculated fair values for all of the Company’s reporting units were considered substantially in excess of the respective reporting unit’s carrying value. Also, the fair value for all of the Company’s intangible assets with indefinite lives were considered substantially in excess of the respective asset carrying values, with one exception. This intangible asset, which represents a trade name within the Company’s Petroleum Services & Supplies segment, had a calculated fair value approximately 13% in excess of its carrying value. Using the discounted cash flows approach, a decrease in the forecasted revenues of 20%, and/or an increase in the discount rate by 200 basis points could yield an impairment of approximately $25 million to $75 million. Based on its analysis, the Company did not report any impairment of goodwill and other indefinite-lived intangible assets for the years ended December 31, 2013, 2012 and 2011.
Purchase Price Allocation of Acquisitions
The Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The Company uses all available information to estimate fair values including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. The Company engages third-party appraisal firms to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, could materially impact the Company’s results of operations.
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with ASC Topic 450 “Contingencies” (“ASC Topic 450”). Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and recognizes them when they are incurred. At December 31, 2013 and 2012, service and product warranties totaled $228 million and $194 million, respectively.
Income Taxes
The Company is a U.S. registered company and is subject to income taxes in the U.S. The Company operates through various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates of the countries in which the Company operates and income is earned.
The Company’s annual tax provision is based on taxable income, statutory rates and tax planning opportunities available in the various jurisdictions in which it operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates. It requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, and treaties, foreign currency exchange restrictions or the Company’s level of operations or profitability in each jurisdiction could impact the tax liability in any given year. The Company also operates in many jurisdictions where the tax laws relating to the pricing of transactions between related parties are open to interpretation, which could potentially result in aggressive tax authorities asserting additional tax liabilities with no offsetting tax recovery in other countries.
The Company maintains liabilities for uncertain tax positions in jurisdictions of operation. The annual tax provision includes the impact of income tax provisions and benefits for changes to liabilities that the Company considers appropriate, as well as related interest. Uncertain tax positions primarily include potential challenges to intercompany pricing and certain operating expenses that may not be deductible in foreign jurisdictions. These exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means. The Company is subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company believes that an appropriate liability has been established for uncertain tax positions under the guidance in ASC Topic 740 “Income Taxes” (“ASC Topic 740”). However, actual results may differ materially from these estimates. The Company reviews these liabilities quarterly and to the extent audits or other events result in an adjustment to the liability accrued for a prior year, the effect will be recognized in the period of the event.
The Company currently has recorded valuation allowances that the Company intends to maintain until it is more likely than not the deferred tax assets will be realized. Income tax expense recorded in the future will be reduced to the extent of decreases in the Company’s valuation allowances. The realization of remaining deferred tax assets is primarily dependent on future taxable income. Any reduction in future taxable income including but not limited to any future restructuring activities may require that the Company record an additional valuation allowance against deferred tax assets. An increase in the valuation allowance would result in additional income tax expense in such period and could have a significant impact on future earnings.
The Company has not provided for deferred taxes on the unremitted earnings of certain subsidiaries that are permanently reinvested. Should the Company make a distribution from the unremitted earnings of these subsidiaries, the Company may be required to record additional taxes. Unremitted earnings of these subsidiaries were $6,045 million and $4,620 million at December 31, 2013 and 2012, respectively. The Company makes a determination each period whether to permanently reinvest these earnings. If, as a result of these reassessments, the Company distributes these earnings in the future, additional tax liabilities would result, offset by any available foreign tax credits.
Recently Issued Accounting Standards
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update No. 2013-02, “Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” (ASU No. 2013-02), which is an update for Accounting Standards Codification Topic No. 220 “Comprehensive Income”. The update improves the reporting of reclassifications out of accumulated other comprehensive income. The guidance was effective for the Company’s interim and annual reporting periods beginning January 1, 2013, and applied prospectively. There was no significant impact to the Company’s Consolidated Financial Statements from the adopted provisions of ASU No. 2013-02.
In March 2013, the FASB issued Accounting Standards Update No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the FASB Emerging Issues Task Force).” (ASU No. 2013-05), which amends Accounting Standards Codification Topic No. 830, “Foreign Currency Matters,” and Accounting Standards Codification Topic No. 810, “Consolidation,” to address diversity in practice related to the release of cumulative translation adjustments (“CTA”) into earnings upon the occurrence of certain derecognition events. ASU No. 2013-05 precludes the release of CTA for derecognition events that occur within a foreign entity, unless such events represent a complete or substantially complete liquidation of the foreign entity; however, derecognition events related to investments in a foreign entity result in the release of all CTA related to the derecognized foreign entity, even when a noncontrolling financial interest is retained. ASU No. 2013-05 also amends Accounting Standards Codification Topic No. 805, “Business Combinations,” for transactions that result in a company obtaining control of a business in a step acquisition by increasing an investment in a foreign entity from one accounted for under the equity method to one accounted for as a consolidated investment. ASU No. 2013-05 is effective for fiscal years beginning after December 15, 2013, and applied prospectively. Early adoption is permitted as of the beginning of the entity’s fiscal year. The Company is currently assessing the impact ASU No. 2013-05 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.
Forward-Looking Statements
Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products and worldwide economic activity. You should also consider carefully the statements under “Risk Factors” which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. During the years ended December 31, 2013, 2012 and 2011, the Company reported foreign currency losses of $26 million, $21 million and $10 million, respectively. Gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. 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, 2013 (in millions except for rates):
The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $875 million and translation exposures totaling $561 million as of December 31, 2013, 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 $57 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $56 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.
Historically, the Venezuelan government has devalued the country’s currency. During the first quarter of 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company incurred approximately $12 million in devaluation charges in the first quarter of 2013. The Company’s net investment in Venezuela was $39 million at December 31, 2013.
Interest Rate Risk
At December 31, 2013, 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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Attached hereto and a part of this report are financial statements and supplementary data listed in Item 15. “Exhibits and Financial Statement Schedules”.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES
(i) Evaluation of disclosure controls and procedures
As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2013 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 63 and is incorporated herein by reference.
(b) Changes in internal control
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Incorporated by reference to the definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Incorporated by reference to the definitive Proxy Statement for the 2014 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, 2013, 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 2014.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Exhibits
(1) Financial Statements
The following financial statements are presented in response to Part II, Item 8:
Page
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of 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
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4)
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8)
3.1
Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, Inc. (Exhibit 3.1) (1)
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9)
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2)
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell. (Exhibit 10.2) (2)
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3)
10.4
National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (5)*
10.5
Form of Employee Stock Option Agreement. (Exhibit 10.1) (6)
10.6
Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (6)
10.7
Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (7)
10.8
Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (7)
10.9
Credit Agreement, dated as of September 28, 2012, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner. (Exhibit 10.1) (10)
10.10
First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (11)
10.11
Second Amendment to Executive Agreement, dated as of December 22, 2008 of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (11)
10.12
First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (11)
10.13
Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (11)
10.14
Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (12)
10.15
Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (12)
10.16
Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (12)
10.17
First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (12)
10.18
Employment Agreement dated as of January 1, 2004 between Jeremy Thigpen and National Oilwell. (Exhibit 10.1) (13)
10.19
First Amendment to Employment Agreement dated as of December 22, 2008 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.2) (13)
10.20
Second Amendment to Employment Agreement dated as of December 31, 2009 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.3) (13)
10.21
Form of Performance Award Agreement (Exhibit 10.1) (14)
21.1
Subsidiaries of the Registrant.
23.1
Consent of Ernst & Young LLP.
24.1
Power of Attorney. (included on signature page hereto)
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Mine Safety Information persuant to section 1503 of the Dodd-Frank Act.
The following materials from our Annual Report on Form 10-K for the period ended December 31, 2013 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (15)
* 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 Appendix I to our Proxy Statement filed on April 10, 2013.
(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) Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2013.
(15) As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NATIONAL OILWELL VARCO, INC.
Dated: February 14, 2014
By:
/s/ MERRILL A. MILLER, JR.
Merrill A. Miller, Jr.
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Each person whose signature appears below in so signing, constitutes and appoints Clay C. Williams and Jeremy D. Thigpen, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.
Signature
Title
Date
/s/ MERRILL A. MILLER, JR.
Merrill A. Miller, Jr.
Chairman and Chief Executive Officer
February 14, 2014
/s/ JEREMY D. THIGPEN
Jeremy D. Thigpen
Senior Vice President and Chief Financial Officer
February 14, 2014
/s/ ROBERT W. BLANCHARD
Robert W. Blanchard
Vice President, Corporate Controller and Chief Accounting Officer
February 14, 2014
/s/ GREG L. ARMSTRONG
Director
February 14, 2014
Greg L. Armstrong
/s/ ROBERT E. BEAUCHAMP
Director
February 14, 2014
Robert E. Beauchamp
/s/ BEN A. GUILL
Director
February 14, 2014
Ben A. Guill
/s/ DAVID D. HARRISON
Director
February 14, 2014
David D. Harrison
/s/ ROGER L. JARVIS
Director
February 14, 2014
Roger L. Jarvis
/s/ ERIC L. MATTSON
Director
February 14, 2014
Eric L. Mattson
/s/ JEFFERY A. SMISEK
Director
February 14, 2014
Jeffery A. Smisek
/s/ CLAY C. WILLIAMS
Director
February 14, 2014
Clay C. Williams
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 February 20, 2013, the Company acquired Robbins & Myers. For purposes of determining the effectiveness of the Company’s internal control over financial reporting, as disclosed in this report, management has excluded the internal controls of Robbins & Myers from its evaluation. The acquired business represented approximately 8% of our consolidated total assets at December 31, 2013, and 3% of consolidated revenues and 4% of our consolidated operating profit for the year ended December 31, 2013.
Management has used the 1992 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, 2013.
The effectiveness of our internal control over financial reporting as of December 31, 2013, 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 14, 2014
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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). National Oilwell Varco, Inc’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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 of Robbins & Myers, which is included in the 2013 consolidated financial statements of the Company and constituted approximately 8% of consolidated total assets at December 31, 2013, and 3% of consolidated revenues and 4% of consolidated operating profit for the year ended December 31, 2013. Our audit of internal control over financial reporting of the Company also did not include the evaluation of internal control over financial reporting of Robbins & Myers.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, 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, 2013 and 2012, 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, 2013 of National Oilwell Varco, Inc. and our report dated February 14, 2014 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 14, 2014
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, 2013 and 2012, 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, 2013. Our audits also included the financial statement schedule listed in the index at item 15(2). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. as of December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 14, 2014, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 14, 2014
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 financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase.
Derivative Financial Instruments
Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges, all derivative financial instruments that the Company holds are designated as cash flow hedges and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog.
Inventories
Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $396 million and $338 million at December 31, 2013 and 2012, 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 $392 million, $323 million and $279 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011.
Intangible Assets
The Company has approximately $9.0 billion of goodwill and $5.1 billion of identified intangible assets at December 31, 2013. 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 $360 million in each of the next five years. Included in intangible assets are approximately $643 million of indefinite-lived trade names.
The net book values 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 2013, 2012 and 2011 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 $26 million, $21 million and $10 million for the years ending December 31, 2013, 2012 and 2011, respectively, and are included in other income (expense) in the accompanying statement of operations.
Historically, the Venezuelan government has devalued the country’s currency. During the first quarter of 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company incurred approximately $12 million in devaluation charges in the first quarter of 2013. The Company’s net investment in Venezuela was $39 million at December 31, 2013.
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 $132 million and $120 million at December 31, 2013 and 2012.
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 $92 million, $80 million and $73 million for 2013, 2012 and 2011, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $28 million, $24 million and $17 million for 2013, 2012 and 2011, respectively.
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated costs and related margins of projects accounted for under percentage-of-completion, estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and other indefinite-lived intangible assets for impairment and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. In circumstances where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than others, the low end of the range is accrued. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous judgments with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.
Net Income Attributable to Company Per Share
The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):
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, 2013, 2012 and 2011 and therefore not excluded from net income attributable to Company per share calculation.
The Company had stock options outstanding that were anti-dilutive totaling 7 million, 5 million, and 3 million at December 31, 2013, 2012 and 2011, respectively.
Recently Issued Accounting Standards
In February 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update No. 2013-02, “Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income” (ASU No. 2013-02), which is an update for Accounting Standards Codification Topic No. 220 “Comprehensive Income”. The update improves the reporting of reclassifications out of accumulated other comprehensive income. The guidance was effective for the Company’s interim and annual reporting periods beginning January 1, 2013, and applied prospectively. There was no significant impact to the Company’s Consolidated Financial Statements from the adopted provisions of ASU No. 2013-02.
In March 2013, the FASB issued Accounting Standards Update No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (a consensus of the FASB Emerging Issues Task Force).” (ASU No. 2013-05), which amends Accounting Standards Codification Topic No. 830, “Foreign Currency Matters,” and Accounting Standards Codification Topic No. 810, “Consolidation,” to address diversity in practice related to the release of cumulative translation adjustments (“CTA”) into earnings upon the occurrence of certain derecognition events. ASU No. 2013-05 precludes the release of CTA for derecognition events that occur within a foreign entity, unless such events represent a complete or substantially complete liquidation of the foreign entity; however, derecognition events related to investments in a foreign entity result in the release of all CTA related to the derecognized foreign entity, even when a noncontrolling financial interest is retained. ASU No. 2013-05 also amends Accounting Standards Codification Topic No. 805, “Business Combinations,” for transactions that result in a company obtaining control of a business in a step acquisition by increasing an investment in a foreign entity from one accounted for under the equity method to one accounted for as a consolidated investment. ASU No. 2013-05 is effective for fiscal years beginning after December 15, 2013, and applied prospectively. Early adoption is permitted as of the beginning of the entity’s fiscal year. The Company is currently assessing the impact ASU No. 2013-05 will have on its financial statements, but does not expect a significant impact from adoption of the pronouncement.
3. Derivative Financial Instruments
The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is foreign currency exchange rate risk. Forward contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk on forecasted revenues and expenses denominated in currencies other than the functional currency of the operating unit (cash flow hedge). Other forward exchange contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk associated with certain firm commitments denominated in currencies other than the functional currency of the operating unit (fair value hedge). In addition, the Company will enter into non-designated forward contracts against various foreign currencies to manage the foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts (non-designated hedge).
At December 31, 2013, the Company has determined that the fair value of its derivative financial instruments representing assets of $59 million and liabilities of $40 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, 2013, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $19 million.
At December 31, 2013, the Company’s financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.
Cash Flow Hedging Strategy
To protect against the volatility of forecasted foreign currency cash flows resulting from forecasted revenues and expenses, the Company has instituted a cash flow hedging program. The Company hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the decrease in present value of future foreign currency revenues and expenses is offset by gains in the fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar weakens, the increase in the present value of future foreign currency cash flows is offset by losses in the fair value of the forward contracts.
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that is subject to a particular currency risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of Other Comprehensive Income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash flows associated with forecasted revenues). The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), or hedge components excluded from the assessment of effectiveness, is recognized in the Consolidated Statements of Income during the current period.
At December 31, 2013 and 2012, 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 $(16) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.
(b) The amount of gain (loss) recognized in income represents nil related to the ineffective portion of the hedging relationships for the each of the years ended December 31, 2013 and 2012, and $12 million and $8 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2013 and 2012, respectively.
4. Acquisitions and Investments
On February 20, 2013, the Company completed its acquisition of all of the shares of Robbins & Myers, Inc. (“R&M”), a U.S.-based designer and manufacturer of products and systems for the oil and gas industry. Under the merger agreement for this transaction, R&M shareholders received $60.00 in cash for each common share for an aggregate purchase price of $2,378 million, net of cash acquired. In addition to R&M, the Company completed five acquisitions and other investments for an aggregate purchase price of $19 million, net of cash acquired.
The Company has included the financial results of R&M in its consolidated financial statements as of the date of acquisition with components of the R&M operations included in the Company’s Rig Technology, Petroleum Services & Supplies and Distribution & Transmission segments. The Company believes the acquisition of R&M will advance its strategic goal of providing a broader selection of products and services to its customers.
The following table displays the total preliminary purchase price allocation for the R&M acquisition. The table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):
The Company has allocated $894 million to identifiable intangible assets (19 year weighted-average life). The intangible assets are amortizable and are comprised of: $635 million of customer relationships (18 year weighted-average life), $170 million of patents (20 year weighted-average life), $86 million of trademarks (20 year weighted-average life), and $3 million of other intangible assets (1 year weighted-average life). The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill specifically includes the expected synergies and other benefits that the Company believes will result from combining its operations with those of businesses acquired and other intangible assets that do not qualify for separate recognition, such as assembled workforce in place at the date of acquisition. Goodwill resulting from the R&M acquisition is not deductible for tax purposes. Pro forma information is not included because the results of the acquired operations would not have materially impacted the Company’s consolidated operating results.
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:
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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.
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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.
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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.
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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 following table displays the total purchase price allocation for the 2012 acquisitions and summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):
The Company allocated $981 million to intangible assets (18 year weighted-average life). The intangible assets are amortizable and are comprised of: $473 million of customer relationships (20 year weighted-average life), $159 million of trademarks (16 year weighted-average life), and $348 million of other intangible assets (17 year weighted-average life). Goodwill specifically includes the expected synergies and other benefits that the Company believes will result from combining its operations with those of businesses acquired and other intangible assets that do not qualify for separate recognition, such as assembled workforce in place at the date of each acquisition. The $1,000 million allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill resulting from the NKT and CE Franklin acquisitions and a portion of the Enerflow acquisition is not deductible for tax purposes. Pro forma information is not included because the results of the acquired operations would not have materially impacted the Company’s consolidated operating results.
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 following table displays the total purchase price allocation for the 2011 acquisitions and summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (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).
Each of the acquisitions was accounted for using the purchase method of accounting and, accordingly, the results of operations of each business are included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions):
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 2013 are as follows (in millions):
The Company has a $3.5 billion, five-year unsecured revolving credit facility which expires September 28, 2018, following a one year extension executed in September 2013. In August 2013, the Company initiated a commercial paper program. Borrowings under the commercial paper program are classified as long-term as the program is supported by the $3.5 billion, five-year revolving credit facility. At December 31, 2013, there were no commercial paper borrowings however, there were $947 million in outstanding letters of credit issued under the credit facility, resulting in $2,553 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the prime rate. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at December 31, 2013.
The Company also had $3,056 million of additional outstanding letters of credit at December 31, 2013, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.
The fair value of the Company’s Senior Notes are estimated using Level 2 inputs in the fair value hierarchy and is based on quoted prices for those or similar instruments. At December 31, 2013 and 2012, the fair value of the Company’s unsecured Senior Notes approximated $2,896 million and $3,190 million, respectively. At December 31, 2013 and 2012, the carrying value of the Company’s unsecured Senior Notes was $3,143 million and $3,142 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, 2013, 2012 and 2011, expenses for defined-contribution plans were $96 million, $82 million, and $54 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, 1,353 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.
As a result of the Robbins & Myers acquisition in February of 2013, the Company acquired four qualified, defined benefit, noncontributory pension plans for certain U.S. employees, an unfunded defined benefit pension plan for eligible employees in Germany, as well as two defined benefit, one contributory, pension plans in the U.K. The U.S. pension plans are closed to all new participants and there are no further benefit accruals under these plans. In addition, 230 U.S. employees covered by a collective bargaining agreement participate in a health care plan that provides postretirement medical benefits (which also covers approximately 400 retirees and dependents). The arrangements in Germany and the U.K. are all closed to new entrants, but benefits continue to accrue for current participants.
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, $10 million and $14 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, Norway, Germany and the Netherlands and defined postretirement plans in the United States, using a measurement date of December 31, 2013 and December 31, 2012, 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 $47 million for each of the next five years and aggregate payments of $479 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):
Level 3 inputs are unobservable (i.e., supported by little or no market activity). Level 3 inputs include management’s own assumption about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).
The following table sets forth a summary of changes in the fair value of the Plan’s Level 3 assets (in millions):
11. Accumulated Other Comprehensive Income (Loss)
The components of accumulated other comprehensive income (loss) are as follows (in millions):
The components of amounts reclassified from accumulated other comprehensive income (loss) are as follows (in millions):
The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in other comprehensive income or loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the year ended December 31, 2013 a majority of these local currencies weakened against the U.S. dollar resulting in a net other comprehensive loss of $90 million upon the translation from local currencies to the U.S. dollar. Due to the sale of a foreign subsidiary during the second quarter of 2013, $25 million of currency translation gains were reclassified from accumulated other comprehensive income (loss) into other income (expense), net in the Consolidated Statements of Income. For the year ended December 31, 2012 a majority of these local currencies strengthened against the U.S. dollar resulting in a net other comprehensive income of $64 million upon the translation from local currencies to the U.S. dollar while for the year ended December 31, 201l a majority of these local currencies weakened against the U.S. dollar resulting in a net other comprehensive loss of $65 million.
The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in other comprehensive income (loss), net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in other comprehensive income (loss) from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of other comprehensive income (loss) related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect was other comprehensive loss of $37 million (net of tax of $18 million) for the year ended December 31, 2013, other comprehensive income of $99 million (net of tax of $39 million) for the year ended December 31, 2012 and other comprehensive loss of $63 million (net of tax of $25 million) for the year ended December 31, 2011.
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 U.S. Department of Justice (“DOJ”), the Department of Commerce Bureau of Industry and Security (“BIS”), the United States Department of Treasury, Office of Foreign Assets Control (“OFAC”), and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.
In 2011, the Company acquired Ameron International Corporation (“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 entered into Tolling Agreements. All of the conduct under review occurred before acquisition of Ameron by the Company. During the third quarter of 2013, the Company settled such matter with OFAC by paying an administrative fine in an amount that was not material to the Company.
On February 20, 2013, the Company acquired Robbins & Myers, Inc. (“R&M”). R&M was subject to an ongoing investigation by the DOJ and the BIS regarding potential export controls violations arising from certain shipments by R&M’s Belgian subsidiary to one customer in Iran, Sudan and Syria in 2005 and 2006. R&M has cooperated with the investigation and is currently negotiating a joint settlement with the DOJ and BIS. We currently anticipate that any administrative fine or criminal 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.
A gain of $102 million was recognized in the third quarter of 2013 related to a legal settlement. The gain was included in revenue of the Company’s Rig Technology segment.
In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. As of December 31, 2013, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific cases referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific cases referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.
Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies hereunder may not result in additional, presently unquantifiable, costs or liabilities to us.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2066. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $406 million, $331 million, and $256 million in 2013, 2012 and 2011, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2013, 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 $389 million and $209 million for the years ended December 31, 2013 and 2012, 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 during the second quarter of 2013, 39.5 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2013, approximately 14.5 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, 2013 under the stock option plans have exercise prices between $9.14 and $84.58 per share, and expire at various dates from January 28, 2014 to February 10, 2023.
The following summarizes options activity:
The following summarizes information about stock options outstanding at December 31, 2013:
The weighted-average fair value of options granted during 2013, 2012 and 2011, was approximately $24.11, $30.01 and $29.52 per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2013 and 2012, was $64 million and $120 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 2013 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, 2013 and changes during 2013 with regard to options under all stock option plans:
At December 31, 2013, total unrecognized compensation cost related to nonvested stock options was $74 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 2013, 2012 and 2011 was approximately $64 million, $55 million and $54 million, respectively. Cash received from option exercises for 2013, 2012 and 2011 was $58 million, $113 million and $96 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $39 million, $42 million and $43 million for 2013, 2012 and 2011, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2013, 2012 and 2011 was not material for any period.
Restricted Shares
The Company issues restricted stock awards and restricted stock units to officers and key employees in addition to stock options. During the year ended December 31, 2013, the Company granted 540,194 shares of restricted stock and restricted stock units with a fair value of $69.33 per share and 16,702 shares of restricted stock with a fair value of $69.17 per share. In addition, the Company granted performance share awards to senior management employees with potential payouts varying from zero to 368,860 shares. The restricted stock and restricted stock units were granted February 15, 2013 and vest on the third anniversary of the date of grant, except for a special grant of 16,352 restricted stock units which vest on the second anniversary of the date of grant (subject to the satisfaction of a performance condition). On May 22, 2013, the 16,702 restricted stock awards, with a fair value of $69.17 per share, 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 share awards were granted on March 22, 2013 and can be earned based on performance against established goals over a three-year performance period. The performance share awards are divided into two equal, independent parts that are subject to two separate performance metrics: 50% with a TSR (total shareholder return) goal (the “TSR Award”) and 50% with an internal ROC (return on capital) goal (the “ROC Award”). During the first quarter of 2013, the Company concluded that the performance conditions relating to the performance-based restricted stock awards granted on February 16, 2010 were not met. As a result, the Company reversed $8 million in previously recognized stock-based compensation expense related to performance-based restricted stock awards that did not vest.
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 2013, 2012 and 2011 was $69.07, $83.79 and $79.53 per share, respectively. There were 340,218; 406,844 and 496,642 restricted stock awards that vested during 2013, 2012 and 2011, respectively. At December 31, 2013, there was approximately $54 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, 2013 and 2012 was $127 million and $128 million, respectively. Included in the change in the balance of unrecognized tax benefits for the period ended December 31, 2013 is a $1 million reduction in the balance of unrecognized tax benefits resulted from the lapse of applicable statutes of limitations in foreign jurisdictions. Of the net decrease of $1 million in the balance of unrecognized tax benefits, the entire $1 million was recorded as a decrease of income tax expense in the current year and is reflected in the “other” category in the income tax rate schedule above. These unrecognized tax benefits are included in the balance of other liabilities in the Consolidated Balance Sheet at December 31, 2013. If the $127 million of unrecognized tax benefits accrued at December 31, 2013 are ultimately realized, $54 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, 2013, the Company recorded as an increase of income tax expense a $0.4 million net increase of accrued interest and penalties related to uncertain tax positions. At December 31, 2013, the Company has accrued approximately $8 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, 2013.
The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Norway, Canada, the United Kingdom, the Netherlands, France and Denmark. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2007 and outside the U.S. for the tax years ending after 2006.
In the United States, the Company has $20 million of net operating loss carryforwards as of December 31, 2013, of which $4 million will expire in 2025, $13 million will expire in 2026, $1 million will expire in 2027, $1 million will expire in 2029 and $1 million will expire in 2030. The potential benefit of $7 million has been reduced by a $7 million valuation allowance. Future income tax payments will be reduced in the event the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $7 million would reduce future income tax expense.
Outside the United States, the Company has $170 million of net operating loss carryforwards as of December 31, 2013, of which $1 million will expire in 2014, $9 million will expire in 2015, $7 million will expire in 2016, $4 million will expire in 2017, $14 million will expire in 2018, $12 million will expire in 2020, $21 million will expire in 2021, $20 million will expire in 2022, $1 million will expire in 2023 and $81 million will carry forward indefinitely. The potential benefit of $44 million has been reduced by a $22 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 $22 million would reduce future income tax expense.
Also in the United States, the Company has $300 million of excess foreign tax credits as of December 31, 2013, of which $73 million will expire in 2018, $71 million will expire in 2020, $142 million will expire in 2022, and $14 million will expire in 2023. These credits have been allotted a valuation allowance of $101 million and would be realized as a reduction of future income tax payments. In addition, there is a reserve for uncertain tax positions of $73 million against a portion of these credits.
During 2013, the Company recorded $371 million in net deferred tax liabilities with a corresponding increase in goodwill related to the 2013 acquisition of Robbins & Myers Inc.
Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $6,045 million and $4,620 million at December 31, 2013 and 2012, 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 9%, 10% and 12% of total revenue from one of its customers for the years ended December 31, 2013, 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:
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data):
17. Proposed Spin-off
On September 24, 2013, the Company announced that its Board of Directors authorized Company management to move forward with exploration of a plan to spin-off the Company’s distribution business from the remainder of the Company, creating two stand-alone, publicly traded corporations. The Company believes that the separation of the distribution business can be accomplished via a tax-efficient spin-off to Company shareholders.
The spin-off is expected to be completed in the first half of 2014 and is subject to market conditions, customary regulatory approvals, the execution of separation and intercompany agreements and final board approval. The separation of the distribution business from the rest of the Company does not require shareholder approval.
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2013, 2012 and 2011
(in millions)