NOV Inc. - Annual Report: 2005 (Form 10-K)
Table of Contents
UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE YEAR ENDED DECEMBER 31, 2005
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-12317
NATIONAL OILWELL VARCO, INC.
(Exact name of registrant as specified in its charter)
Delaware | 76-0475815 | |
(State or other jurisdiction | (IRS Employer | |
of incorporation or organization) | Identification No.) |
10000 Richmond Avenue
Houston, Texas
77042-4200
Houston, Texas
77042-4200
(Address of principal executive offices)
(713) 346-7500
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $.01 | New York Stock Exchange | |
(Title of Class) | (Exchange on which registered) |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15 (d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The aggregate market value of voting and non-voting common stock held by non-affiliates of the
registrant as of June 30, 2005 was $8.23 billion. As of February 27, 2006, there were 174,720,766
shares of the Companys common stock ($0.01 par value) outstanding.
Documents Incorporated by Reference
Portions of the Proxy Statement in connection with the 2006 Annual Meeting of Stockholders are
incorporated in Part III of this report.
TABLE OF CONTENTS
Table of Contents
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 500 locations across six continents.
On March 11, 2005, we acquired all of the outstanding shares of Varco International, Inc. (Varco)
with the issuance of 0.8363 shares of National-Oilwell, Inc. common stock for each Varco common share (the Merger).
The Company then changed its name from National-Oilwell, Inc. to
National Oilwell Varco, Inc. We have included the financial results of Varco in our consolidated financial statements beginning
March 11, 2005, the date Varco common shares were exchanged for NOV common shares. We believe that
the Merger has better positioned us to compete more effectively in the global marketplace and
provide greater scale to increase service to our customers, increase our investment in research and
development to accelerate innovation, and increase shareholder value.
The Companys principal executive offices are located at 10000 Richmond Avenue, Houston, Texas
77042, its telephone number is (713) 346-7500, and its Internet web site address is
http://www.nov.com. The Companys 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 Companys Code of
Ethics is also posted on our 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 Companys common stock
is traded on the New York Stock Exchange under the symbol NOV. The Company operates through three
business segments: Rig Technology, Petroleum Services and Supplies, and Distribution Services.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the
drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line
of highly-engineered equipment that automates complex well construction and management operations,
such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly
systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches;
and cranes. Demand for Rig Technology products is primarily dependent on capital spending plans by
drilling contractors, oilfield service companies, and oil and gas companies, and secondarily on the
overall level of oilfield drilling activity, which drives demand for spare parts for the segments
large installed base of equipment. We have made strategic acquisitions and other investments during
the past several years in an effort to expand our product offering and our global manufacturing
capabilities, including new operations in Canada, Norway, the United Kingdom, China, and Belarus.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including transfer pumps, solids control systems, drilling motors and other downhole tools, rig instrumentation systems, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drillpipe, linepipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including operations in Canada, the United Kingdom, China, Kazakhstan, and Mexico.
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including transfer pumps, solids control systems, drilling motors and other downhole tools, rig instrumentation systems, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drillpipe, linepipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including operations in Canada, the United Kingdom, China, Kazakhstan, and Mexico.
Distribution Services
Our Distribution Services segment provides maintenance, repair and operating supplies and spare
parts to drill site and production locations worldwide. In addition to its comprehensive network of
field locations supporting land drilling operations throughout North America, the segment supports
major offshore drilling contractors through locations in the Middle East, Europe, Southeast Asia
and South America. Distribution Services employs advanced information technologies to provide
complete procurement, inventory management and logistics services to its customers around the
globe. Demand for the segments services are determined primarily by the level of drilling and
servicing activity, and oil and gas production activities.
The following table sets forth the contribution to the Companys total revenues of its three
operating segments for December 31, 2005, 2004, and 2003 (in millions):
Years ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Revenue: |
||||||||||||
Rig Technology |
$ | 2,216.8 | $ | 1,085.5 | $ | 880.1 | ||||||
Petroleum Services &
Supplies |
1,645.8 | 505.5 | 446.3 | |||||||||
Distribution Services |
1,074.5 | 905.1 | 792.0 | |||||||||
Eliminations |
(292.6 | ) | (178.0 | ) | (113.5 | ) | ||||||
Total Revenue |
$ | 4,644.5 | $ | 2,318.1 | $ | 2,004.9 | ||||||
See Note
15 to our 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.
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In
accordance with New York Stock Exchange Rules, last year the Company
filed the annual certification by our CEO that, as of the date of the
certification, the Company was in compliance with the New York Stock
Exchanges corporate governance listing standards.
The Company has included a glossary of technical terms at the end of Item 1 of this Annual Report.
Influence of Oil and Gas Activity Levels on the Companys Business
The oil and gas industry in which the Company participates has historically experienced significant
volatility. Demand for the Companys 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 spur
demand for the Companys products and services used to drill and remediate oil and gas wells.
Additionally, high levels of oil and gas activity increase cash flows available for drilling
contractors, oilfield service companies, and manufacturers of oil country tubular goods to invest
in capital equipment which the Company sells.
In 2005, most of the Companys Rig Technology revenue resulted from major capital expenditures of
drilling contractors, well servicing companies, and oil companies on rig construction and
refurbishment, and well servicing equipment. These capital expenditures are influenced by the
amount of cash flow that contractors and service companies generate from drilling, completion, and
remediation activity; as well as by the availability of financing, the outlook for future drilling
and well servicing activity, and other factors. Generally the Company believes the demand for
capital equipment lags increases in the level of drilling activity. The remainder of the Rig
Technology segments revenue in 2005 was 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 Companys Petroleum Services & Supplies revenue is closely tied to drilling
activity, although a portion is related to the sale of capital equipment to drilling contractors,
which may somewhat lag the level of drilling activity. Portions of the segments 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; (ii) the performance of in-service pipeline
inspections; (iii) the sale of fiberglass and composite tubing to industrial customers, which is
generally unrelated to drilling or well remediation activity but may be tied somewhat to oil and
gas prices; and (iv) the sale of pipe inspection equipment to the manufacturers of oil country
tubular goods, which is indirectly related to drilling activity.
The Companys revenue from Distribution Services is almost entirely driven by drilling activity and
oil and gas production activities.
Drilling and well servicing activity can fluctuate significantly in a short period of time. The
willingness of oil and gas operators to make capital investments to explore for and produce oil and
natural gas will continue to be influenced by numerous factors over which the Company has no
control, including: the ability of the members of the Organization of Petroleum Exporting Countries
(OPEC) to maintain oil price stability through voluntary production limits of oil; the level of
oil production by non-OPEC countries; supply and demand for oil and natural gas; general economic
and political conditions; costs of exploration and production; the availability of new leases and
concessions; and governmental regulations regarding, among other things, environmental protection,
taxation, price controls and product allocations. The willingness of drilling contractors and well
servicing companies to make capital expenditures for the type of specialized equipment the Company
provides is also influenced by numerous factors over which the Company has no control, including:
the general level of oil and gas well drilling and servicing; rig dayrates; access to external
financing; outlook for future increases in well drilling and well remediation activity; steel
prices and fabrication costs; and government regulations regarding, among other things,
environmental protection, taxation, and price controls.
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On a worldwide basis, drilling activity was generally high in 2001, but began to decline toward the
end of the year due to lower oil and gas prices. This situation persisted throughout 2002.
However, beginning in late 2002, higher gas prices in the U.S. led to rising gas drilling activity
in Canada and most U.S. onshore areas. Higher oil prices also led to higher drilling activity
levels in 2003 in several international markets, including the Middle East, the Far East and
several key Latin American markets. However, other historically important markets for the Company
remained slow in 2003, including the Gulf of Mexico, the North Sea, and Venezuela. At the same
time, due to the fact that the demand for capital equipment tends to lag drilling activity, the
demand for the Companys capital equipment generally weakened in 2003. This resulted in declining
backlogs through the year.
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 10 percent in 2004 and 15 percent in 2005. As a result of higher cash flows realized by many drilling contractors
and other oilfield service companies, as well as the long-term concerns about supply-demand
imbalance, market conditions for capital equipment purchases have improved significantly since
early 2004, resulting in higher backlogs for the Company at the end of 2005 compared to the end of
2004.
Overview of Oil and Gas Well Drilling and Servicing Processes
Oil and gas wells are usually drilled by drilling contractors using a drilling rig. A bit is
attached to the end of a drill stem, which is assembled by the drilling rig and its crew from
30-foot joints of drillpipe and specialized drilling components known as downhole tools. Using the
conventional rotary drilling method, the drill stem is turned from the rotary table of the drilling
rig by torque applied to the kelly, which is screwed into the top of the drill stem. Increasingly,
drilling is performed using a drilling motor, which is attached to the bottom of the drill stem and
provides rotational force directly to the bit, rather than such force being supplied by the rotary
table. The use of a drilling motor permits the drilling contractor to drill directionally,
including horizontally. The Company sells and rents drilling motors and downhole tools through its
Petroleum Services & Supplies segment.
During drilling, heavy drilling fluids or drilling muds are pumped down the drill stem and forced
out through jets in the bit. The drilling mud returns to the surface through the space between the
borehole wall and the drill stem, carrying with it the drill cuttings drilled out by the bit. The
drill cuttings are removed from the mud by a solids control system (which can include shakers,
centrifuges and other specialized equipment) and disposed of in an environmentally sound manner.
The solids control system permits the mud, which is often comprised of expensive chemicals, to be
continuously reused and recirculated back into the hole.
Through its Rig Technology segment, the Company sells the large mud pumps that are used to pump
drilling mud through the drill stem. Through its Petroleum Services & Supplies business, the
Company sells transfer pumps and mud pump consumables; sells and rents solids control equipment;
and provides solids control and waste management services. Many operators internally coat the drill
stem to protect it from corrosive fluids sometimes encountered during drilling, and inspect and
assess the integrity of the drill pipe from time to time. The Company provides drillpipe inspection
and coating services, and applies hardbanding material to drillpipe to improve its wear
characteristics. These services are provided through the Companys Petroleum Services & Supplies
segment.
As the hole depth increases, the kelly must be removed frequently so that additional 30-foot joints
of drill pipe can be added to the drill stem. When the bit becomes dull or the equipment at the
bottom of the drill stem including the drilling motors otherwise requires servicing, the entire
drill stem is pulled out of the hole and disassembled by disconnecting the joints of drillpipe.
These are set aside or racked, the old bit is replaced or service is performed, and the drill
stem is reassembled and lowered back into the hole (a process called tripping). During drilling
and tripping operations, joints of drill pipe must be screwed together and tightened (made up),
and loosened and unscrewed (spun out). The Companys Rig Technology business provides drilling
equipment to manipulate and maneuver the drill pipe in this manner. When the hole has reached
certain depths, all of the drill pipe is pulled out of the hole and larger diameter pipe known as
casing is lowered into the hole and permanently cemented in place in order to protect against
collapse and contamination of the hole. The casing is typically inspected before it is lowered into
the hole, a service the Companys Petroleum Services & Supplies business provides. The Companys
Rig Technology segment manufactures pressure pumping equipment that is used to cement the casing in
place.
The raising and lowering of the drill stem while drilling or tripping, and the lowering of casing
into the wellbore, are accomplished with the rigs hoisting system. A conventional hoisting system
is a block and tackle mechanism that works within the drilling rigs derrick. The lifting of this
mechanism is performed via a series of pulleys that are attached to the drawworks at the base of
the derrick. The Companys Rig Technology segment sells and installs drawworks and pipe hoisting
systems.
During the course of normal drilling operations, the drill stem passes through different geological
formations, which exhibit varying pressure characteristics. If this pressure is not contained, oil,
gas and/or water would flow out of these formations to the surface. The two means of containing
these pressures are (i) primarily the circulation of drilling muds while drilling and (ii)
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secondarily the use of blowout preventers should the mud prove inadequate and in an emergency
situation. The Companys Rig Technology group sells and services blowout preventers.
Drilling muds are carefully designed to exhibit certain qualities that optimize the drilling
process. In addition to containing formation pressure, they must (i) provide power to the drilling
motor, (ii) carry drilled solids to the surface, (iii) protect the drilled formations from being
damaged, and (iv) cool the drill bit. Achieving these objectives often requires a formulation
specific to a given well and can involve the use of expensive chemicals as well as natural
materials such as certain types of clay. The fluid itself is often oil or more-expensive synthetic
mud. Given this expense, it is highly desirable to reuse as much of the drilling mud as possible.
Solids control equipment such as shale shakers, centrifuges, cuttings dryers, and mud cleaners help
accomplish this objective. The Companys Petroleum Services & Supplies group rents, sells, operates
and services this equipment. Drilling muds are formulated based on expected drilling conditions.
However, as the hole is drilled, the drill stem may encounter a high pressure zone where the mud
density is inadequate to maintain sufficient pressure. Should efforts to weight up the mud in
order to contain such a pressure kick fail, a blowout could result, whereby reservoir fluids would
flow uncontrolled into the well. To prevent blowouts to the surface of the well, a series of
high-pressure valves known as blowout preventers (BOPs) are positioned at the top of the well
and, when activated, form tight seals that prevent the escape of fluids. When closed, conventional
BOPs prevent normal rig operations. Therefore, the BOPs are activated only if drilling mud and
normal well control procedures cannot safely contain the pressure. BOPs have been designed to
contain pressures of up to 20,000 psi. The Company sells and services BOPs through its Rig
Technology segment.
The operations of the rig and the condition of the drilling mud are closely monitored by various
sensors, which measure operating parameters such as the weight on the rigs hook, the incidence of
pressure kicks, the operation of the drilling mud pumps, etc. Through its Petroleum Services &
Supplies business, the Company sells and rents drilling rig instrumentation packages that perform
these monitoring functions.
During the drilling and completion of a well, there exists an ongoing need for various consumables
and spare parts. While most of these items are small, in the aggregate they represent an important
element of the process. Since it is impractical for each drilling location to have a full supply
of these items, drilling contractors and well service companies tend to rely on third parties to
stock and deliver these items. The Company provides this capability through its Distribution
Services segment, which stocks and sells spares and consumables made by third parties, as well as
spares and consumables by the company.
After the well has reached its total depth and the final section of casing has been set, the
drilling rig is moved off of the well and the well is prepared to begin producing oil or gas in a
process known as well completion. Well completion usually involves installing production tubing
concentrically in the casing. Due to the corrosive nature of many produced fluids, production
tubing is often inspected and coated, services offered by the Companys Petroleum Services &
Supplies business. Sometimes operators choose to use corrosion resistant composite materials (which
the Company offers through its Petroleum Services & Supplies business), or corrosion-resistant
alloys, or operators sometimes pump fluids into wells to inhibit corrosion.
From time to time, a producing well may undergo workover procedures to extend its life and increase
its production rate. Workover rigs are used to disassemble the wellhead, tubing and other
completion components of an existing well in order to stimulate or remediate the well. Workover
rigs are similar to drilling rigs in their capabilities to handle tubing, but are usually smaller
and somewhat less sophisticated. The Company offers a comprehensive range of workover rigs through
its Rig Technology segment. Tubing and sucker rods removed from a well during a well remediation
operation are often inspected to determine their suitability to be reused in the well, which is a
service the Companys Petroleum Services & Supplies business provides.
Frequently coiled tubing units or wireline units are used to accomplish certain well remediation
operations or well completions. Coiled tubing is a recent advancement in petroleum technology
consisting of a continuous length of reeled steel tubing which can be injected concentrically into
the production tubing all the way to the bottom of most wells. It permits many operations to be
performed without disassembling the production tubing, and without curtailing the production of the
well. Wireline winch units are devices that utilize single-strand or multistrand wires to perform
well-remediation operations, such as lowering tools and transmitting data to the surface. Through
the Rig Technology group, the Company sells and rents various types of coiled tubing equipment, and
wireline equipment and tools. The Company also manufactures and sells coiled tubing pipe through
its Petroleum Services & Supplies segment.
Rig Technology
The Company has a long tradition of pioneering innovations in drilling and well servicing equipment
which improve the efficiency, safety, and cost of drilling and well servicing operations. The Rig
Technology group designs, manufactures and sells a wide variety of top drives, automated pipe
racking systems, motion compensation systems, rig controls, BOPs, handling tools, drawworks,
risers, rotary tables, mud pumps, cranes and other drilling equipment for both the onshore and
offshore markets. The
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Rig Technology group also manufactures entire rig packages, both drilling and workover, as well as
well servicing equipment such as coiled tubing units, pressure pumping equipment, and wireline
winches.
The Rig Technology group sells directly to drilling contractors, shipyards and other rig
fabricators, well servicing companies, national oil companies, major and independent oil and gas
companies, supply stores, and pipe-running service providers. Demand for its products, several of
which are described below, is strongly dependent upon capital spending plans by oil and gas
companies and drilling contractors, and the level of oil and gas well drilling activity.
Top Drives. The Top Drive Drilling System (TDS), originally introduced by the Company in 1982,
significantly alters the traditional drilling process. The TDS rotates the drill stem from its top,
rather than by the rotary table, with a large electric motor affixed to rails installed in the
derrick that traverses the length of the derrick to the rig floor. Therefore, the TDS eliminates
the use of the conventional rotary table for drilling. Components of the TDS also are used to
connect additional joints of drill pipe to the drill stem during drilling operations.
The TDS combines elements of pipe handling tools, as well as hoisting and rotary equipment, into a
single system. During drilling operations, the TDS performs functions such as making-up joints of
drill pipe, maneuvering joints of drill pipe into position to be added to the drill stem when
drilling, and holding and hoisting the entire drill stem. Drilling with a TDS provides several
advantages over conventional drilling. It enables drilling with three joints of drill pipe, often
reducing by two-thirds the time spent in making connections of drill pipe. In addition, it
facilitates horizontal and extended reach drilling (the practice of drilling wells which
deviate substantially from vertical) by providing the ability to rotate the pipe as it is removed
from, or placed into, the well, thus reducing the likelihood of the drill stem becoming stuck in
the wellbore a phenomenon that may occur when drill pipe remains stationary in the wellbore for a
prolonged period. By facilitating extended reach drilling, the TDS increases the area which can be
drilled from a given location, such as a fixed platform. Thus, the production from a given
reservoir of oil can be increased, and the number of costly fixed platforms required to develop the
field can be minimized.
Rotary Equipment. The alternative to using a TDS to rotate the drill stem is to use a rotary
table, which rotates the pipe at the floor of the rig. The Rig Technology group produces rotary
tables as well as kelly bushings and master bushings for most sizes of kellys and makes of rotary
tables. In 1998, NOV introduced the Rotary Support Table for use on rigs with a TDS. The Rotary
Support Table is used in concert with the TDS to completely eliminate the need for the larger
conventional rotary table.
Pipe Handling Systems. Pipe racking systems are used to handle drill pipe, casing and tubing on
a drilling rig. Vertical pipe racking systems move drill pipe and casing between the well and a
storage (racking) area on the rig floor. Horizontal racking systems are used to handle tubulars
while stored horizontally (for example, on the pipe deck of an offshore rig) and transport tubulars
up to the rig floor and into a vertical position for use in the drilling process.
Vertical pipe racking systems are used predominantly on offshore rigs and are found on almost all
floating rigs. Mechanical vertical pipe racking systems greatly reduce the manual effort involved
in pipe handling. The Pipe Handling Machine (PHM), introduced by NOV in 1985, provides a fully
automated mechanism for handling and racking drill pipe during drilling and tripping operations,
spinning and torquing drill pipe, and automatic hoisting and racking of disconnected joints of
drill pipe. These functions can be integrated via computer controlled sequencing, and operated by a
driller in an environmentally secure cabin. An important element of this system is the Iron
Roughneck, which was originally introduced by NOV in 1976 and is an automated device that makes
pipe connections on the rig floor and requires less direct involvement of rig floor personnel in
potentially dangerous operations. The Automated Roughneck is an automated microprocessor-controlled
version of the Iron Roughneck.
Horizontal pipe racking systems were introduced by NOV in 1993. They include the Pipe Deck Machine
(PDM), which is used to manipulate and move tubulars while stored in a horizontal position; the
Pipe Transfer Conveyor (PTC), which transports sections of pipe to the rig floor; and a Pickup
Laydown System (PLS), which raises the pipe to a vertical position for transfer to a vertical
racking system. These components may be employed separately, or incorporated together to form a
complete horizontal racking system, known as the Pipe Transfer System (PTS).
Mud Pumps. Mud pumps are high pressure pumps located on the rig that force drilling mud down the
drill pipe, through the drill bit, and up the space between the drill pipe and the drilled
formation (the annulus) back to the surface. These pumps, which generate pressures of up to 7500
psi, must therefore be capable of displacing drilling fluids several thousand feet down and back up
the well bore. Marketed under the brand names NationalTM, OilwellTM, and
Continental EmscoTM, the conventional mud pump design, known as the triplex pump, uses
three reciprocating pistons oriented horizontally. Recently, NOV has introduced the HEX Pump,
which uses six pumping cylinders, versus the three used in the triplex pump. Along with other
design features, the greater number of cylinders reduces pulsations (or surges) and increases the
output available from a given footprint. Reduced pulsation in particular desirable where downhole
measurement equipment is being used during the drilling process, as is often the case in
directional drilling.
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Hoisting Systems. Hoisting systems are used to raise or lower the drill stem while drilling or
tripping, and to lower casing into the wellbore. The drawworks is the heart of the hoisting system.
It is a large winch that spools off or takes in the drilling line, which is in turn connected to
the drill stem at the top of the derrick. The drawworks also plays an important role in keeping
the weight on the drill bit at a desired level. This task is particularly challenging on offshore
drilling rigs, which are subject to wave motion. To address this, NOV has introduced the Active
Heave Drilling (AHD) Drawworks. The AHD Drawworks uses computer-controlled motors to compensate
for the motion experienced in offshore drilling operations.
Motion Compensation Systems. Motion compensation equipment stabilizes the bit on the bottom of the
hole, increasing drilling effectiveness of floating offshore rigs by compensating for wave and wind
action. Tensioners provide continuous axial tension to the marine riser pipe (larger diameter pipe
which connects floating drilling rigs to the well on the ocean floor) and guide lines on floating
drilling rigs, tension leg platforms and jack-up drilling rigs. In addition to the AHD Drawworks
discussed above, NOV has introduced an Active Heave Compensation (AHC) System that goes beyond
the capabilities of the AHD Drawworks to handle the most severe weather.
Blow-out Preventers. BOPs are devices used to seal the space (annulus) between the drill pipe
and the borehole to prevent blow-outs (uncontrolled flows of formation fluids and gases to the
surface). The Rig Technology group manufactures a wide array of BOPs used in various situations.
Ram and annular BOPs are back-up devices that are activated only if other techniques for
controlling pressure in the wellbore are inadequate. When closed, these devices prevent normal rig
operations. Ram BOPs seal the wellbore by hydraulically closing rams (thick heavy blocks of steel)
against each other across the wellbore. Specially designed packers seal around specific sizes of
pipe in the wellbore, shear pipe in the wellbore or close off an open hole. Annular BOPs seal the
wellbore by hydraulically closing a rubber packing unit around the drill pipe or kelly or by
sealing against itself if nothing is in the hole. NOVs Pressure Control While Drilling (PCWD)
BOP, introduced in 1995, allows operators to drill at pressures up to 2,000 psi without
interrupting normal operations, and can act as a normal spherical BOP at pressures up to 5,000 psi.
In 1998 NOV introduced the NXT® ram type BOP which eliminates door bolts, providing
significant weight, rig-time, and space savings. Its unique features make subsea operation more
efficient through faster ram configuration changes without tripping the BOP stack. In 2004, NOV
introduced the LXT, which features many of the design elements of the NXT, but is targeted at the
land market.
The conventional BOP control system is hydraulically activated and is used to operate BOPs and
associated valves remotely for both land systems and offshore systems. With the recent increase in
deep-water drilling depths, traditional hydraulic control systems are inadequate to activate BOPs,
which rest on the ocean floor and may be 5,000 feet or more below the surface. In 1997, NOV
introduced the IVth Subsea Generation MUX, an electronic control system designed specifically for
deep-water applications. In 2005, the Company began commercializing technology related to a
continuous circulation device. This device enables drilling contractors to make and break drill
pipe connections without stopping the circulation of drilling fluids. This in turn increases
drilling efficiency.
Pipe Handling Tools. The Companys pipe handling tools are designed to enhance the safety,
efficiency and reliability of pipe handling operations. Many of these tools have provided
innovative methods of performing the designated task through mechanization of functions previously
performed manually. The Rig Technology group manufactures various tools used to grip, hold, raise,
and lower pipe, and in the making up and breaking out of drill pipe, workstrings, casing and
production tubulars including spinning wrenches, manual tongs, torque wrenches and kelly spinners.
The Rig Technology group also manufactures other tools used in various pipe handling functions.
Slips are gripping devices which hold pipe or casing in suspension while in the hole. Other
products, which include safety clamps, casing bushings and casing bowls, are used to hold and guide
drill pipe or casing while in the hole, prevent tool strings from being dropped down the well
accidentally, and ensure that the casing is centered in the hole.
Derricks and substructures. Drilling activities are carried out from a drilling rig. A drilling
rig consists of one or two derricks; the substructure that supports the derrick(s); and the rig
package, which consists of the various pieces of equipment discussed above. The Rig Technology
segment designs, fabricates and services derricks used in both onshore and offshore applications,
and substructures used in onshore applications. The Rig Technology group also works with shipyards
in the fabrication of substructures for offshore drilling rigs.
Coiled Tubing Equipment. Coiled tubing consists of flexible steel tubing manufactured in a
continuous string and spooled on a reel. It can extend several thousand feet in length and is run
in and out of the wellbore at a high rate of speed by a hydraulically operated coiled tubing unit.
A coiled tubing unit is typically mounted on a truck or skid (steel frames on which portable
equipment is mounted to facilitate handling with cranes or flatbed trucks) and consists of a
hydraulically operated tubing reel or drum, an injector head which pushes or pulls the tubing in or
out of the wellbore, and various power and control systems. Coiled
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tubing is typically used with sophisticated pressure control equipment which permits the operator
to continue to safely produce the well. The Rig Technology group manufactures and sells both coiled
tubing units and the ancillary pressure control equipment used in these operations.
Currently, most coiled tubing units are used in well remediation and completion applications. The
Company believes that advances in the manufacturing process of coiled tubing, tubing fatigue
protection and the capability to manufacture larger diameter and increased wall thickness coiled
tubing strings have resulted in increased uses and applications for coiled tubing products. For
example, some well operators are now using coiled tubing in drilling applications such as slim hole
reentries of existing wells. NOV engineered and manufactured the first coiled tubing units built
specifically for coiled tubing drilling in 1996.
Generally, The Rig Technology group supplies customers with the equipment and components necessary
to use coiled tubing, which the customers typically purchase separately. The groups coiled tubing
product line consists of coiled tubing units, coiled tubing pressure control equipment, pressure
pumping equipment, snubbing units (which are units that force tubulars into a well when pressure is
contained within the wellbore), nitrogen pumping equipment and cementing, stimulation, fracturing
and blending equipment.
Wireline Equipment. NOVs wireline products include wireline drum units, which consist of a
spool or drum of wireline cable, mounted in a mobile vehicle or skid, which works in conjunction
with a source of power (an engine mounted in the vehicle or within a separate power pack skid).
The wireline drum unit is used to spool wireline cable into or out of a well, in order to perform
surveys inside the well, sample fluids from the bottom of the well, retrieve or replace components
from inside the well, or to perform other well remediation or survey operations. The wireline used
may be slickline, which is conventional steel cable used to convey tools in or out of the well,
or electric line, which contains an imbedded single-conductor or multi-conductor electrical line
which permits communication between the surface and electronic instruments attached to the end of
the wireline at the bottom of the well.
Wireline units are usually used in conjunction with a variety of other pressure control equipment
which permit safe access into wells while they are flowing and under pressure at the surface. The
company engineers and manufactures a broad range of pressure control equipment for wireline
operations, including wireline blowout preventers, strippers, packers, lubricators and grease
injection units. Additionally, the Company makes wireline rigging equipment such as mast trucks.
Facilities. The Company conducts Rig Technology manufacturing operations at major facilities in
Houston, Galena Park, Sugurland, Conroe, Fort Worth and Pampa, Texas; Tulsa, Oklahoma; Orange,
California; Calgary, Nisku and Edmonton, Canada; Mexicali, Mexico; Kristiansand, Norway;
Etten-Leur, the Netherlands; Carquefou, France; and Lanzhou, China. The Rig Technology group
maintains sales and service offices in most major oilfield markets, either directly or through
agents.
Customers and Competition. The Rig Technology segment sells directly to drilling contractors,
other rig fabricators, well servicing companies, national oil companies, major and independent oil
and gas companies, supply stores, and pipe-running service providers. Demand for its products is
strongly dependent upon capital spending plans by oil and gas companies and drilling contractors,
and the level of oil and gas well drilling activity.
The products of the Rig Technology group are sold in highly competitive markets and its sales and
earnings can be affected by competitive actions such as price changes, new product development, or
improved availability and delivery. The groups primary competitors are Access Oil Tools; Aker
Kvaerner AS; American Block; Canrig (a division of Nabors Industries); Cavins Oil Tools; Cooper
Cameron Corporation; DenCon Oil Tools; Hydril Company; LEWCO (a division of Rowan Companies); Tesco
Corporation; Wirth M&B GmbH; Stewart & Stevenson, Inc.; ASEP; Crown Energy Technologies; Rolligon;
Huntings, Ltd.; Vanoil; Parveen Industries; and Weatherford International, Inc. Management believes
that the principal competitive factors affecting its Drilling Equipment business are performance,
quality, reputation, customer service, availability of products, spare parts, and consumables, and
breadth of product line and price.
Petroleum Services & Supplies
The Company provides a broad range of support equipment, spare parts, consumables and services
through the Petroleum Services & Supplies segment. The Petroleum Services & Supplies group sells
directly to drilling contractors; well servicing companies; oil and gas producers; national oil
companies; tubular processors, manufacturers and distributors; oilfield distributors; and pipeline
operators.
The Petroleum Services & Supplies group provides a variety of tubular services, composite tubing,
and coiled tubing to oil and gas producers, national oil companies, drilling contractors, well
servicing companies, pipeline operators, and tubular processors, manufacturers and distributors.
These include inspection and reclamation services for drill pipe, casing, production tubing, sucker
rods and line pipe at drilling and workover rig locations, at yards owned by its customers, at
steel mills and processing facilities
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that manufacture tubular goods, and at facilities which it owns. The group also provides internal
coating of tubular goods at several coating plants worldwide and through licensees in certain
locations. Additionally, the Company designs, manufactures and sells high pressure fiberglass and
composite tubulars for use in corrosive applications and coiled tubing for use in well servicing
applications; and provides in-service inspection of oil, gas and product transmission pipelines
through its application of instrumented survey tools (smart pigs) which it engineers,
manufactures and operates.
The Companys customers rely on tubular inspection services to avoid failure of tubing, casing,
flowlines, pipelines and drill pipe. Such tubular failures are expensive and in some cases
catastrophic. The Companys customers rely on internal coatings of tubular goods to prolong the
useful lives of tubulars and to increase the volumetric throughput of in-service tubular goods. The
Companys customers sometimes use fiberglass or composite tubulars in lieu of conventional steel
tubulars, due to the corrosion-resistant properties of fiberglass and other composite materials.
Tubular inspection and coating services are used most frequently in operations in high-temperature,
deep, corrosive oil and gas environments. In selecting a provider of tubular inspection and tubular
coating services, oil and gas operators consider such factors as reputation, experience, technology
of products offered, reliability and price.
The Companys Petroleum Services & Supplies group also provides products and services that are used
in the course of drilling oil and gas wells. The Downhole Tools business sells and rents drilling
motors and specialized downhole tools that are incorporated into the drill stem during drilling
operations (Downhole Tools), and are also used during fishing, well intervention, re-entry, and
well completion operations. The Solids Control business is engaged in the provision of
highly-engineered equipment, products and services which separate and manage drill cuttings
produced by the drilling process (Solids Control). Drill cuttings are usually contaminated with
petroleum or drilling fluids, and must be disposed of in an environmentally sound manner.
Additionally, efficient separation of drill cuttings enables the re-use of often costly drilling
fluids. The Instrumentation business rents and sells proprietary drilling rig instrumentation
packages and control systems which monitor various processes throughout the drilling operation,
under the name MD/Totco (Instrumentation). The Pumps & Expendables business provides centrifugal,
reciprocating, and progressing cavity pumps and pump expendables (Pumps & Expendables) into the
global oil and gas and industrial markets.
Tubular Coating. The Company develops, manufactures and applies its proprietary tubular coatings,
known as Tube-Kote® coatings, to new and used tubulars. Tubular coatings help prevent
corrosion of tubulars by providing a tough plastic shield to isolate steel from corrosive oilfield
fluids such as CO2, H2S and brine. Delaying or preventing corrosion extends
the life of existing tubulars, reduces the frequency of well remediation and reduces expensive
interruptions in production. In addition, coatings are designed to increase the fluid flow rate
through tubulars by decreasing or eliminating paraffin and scale build-up, which can reduce or
block oil flow in producing wells. The smooth inner surfaces of coated tubulars often increase the
fluid through-put on certain high-rate oil and gas wells by reducing friction and turbulence. The
Companys reputation for supplying quality internal coatings is an important factor in its
business, since the failure of coatings can lead to expensive production delays and premature
tubular failure.
In 2005, NOV created a 60%-owned joint venture in China with the Huabei Petroleum Administration
Bureau, which coats Chinese produced drill pipe using NOVs proprietary coatings.
Tubular Inspection. Newly manufactured pipe sometimes contains serious defects that are not
detected at the mill. In addition, pipe can be damaged in transit and during handling prior to use
at the well site. As a result, exploration and production companies often have new tubulars
inspected before they are placed in service to reduce the risk of tubular failures during drilling,
completion, or production of oil and gas wells. Used tubulars are inspected by the Company to
detect service-induced flaws after the tubulars are removed from operation. Used drill pipe and
used tubing inspection programs allow operators to replace defective lengths, thereby prolonging
the life of the remaining pipe and saving the customer the cost of unnecessary tubular replacements
and expenses related to tubular failures.
Tubular inspection services employ all major non-destructive inspection techniques, including
electromagnetic, ultrasonic, magnetic flux leakage and gamma ray. These inspection services are
provided both by mobile units which work at the wellhead as used tubing is removed from a well, and
at fixed site tubular inspection locations. The group provides an ultrasonic inspection service for
detecting potential fatigue cracks in the end area of used drill pipe, the portion of the pipe that
traditionally has been the most difficult to inspect. Tubular inspection facilities also offer a
wide range of related services, such as API thread inspection, ring and plug gauging, and a
complete line of reclamation services necessary to return tubulars to useful service, including
tubular cleaning and straightening, hydrostatic testing and re-threading.
In addition, the Company applies hardbanding material to drillpipe, to enhance its wear
characteristics and reduce downhole casing wear as a result of the drilling process. In 2002, the
Company introduced its proprietary line of hardbanding material, TCS 8000ä. The group also
cleans, straightens, inspects and coats sucker rods at 11 facilities throughout the Western
Hemisphere.
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Additionally, new sucker rods are inspected before they are placed into service, to avoid premature
failure, which can cause the oil well operator to have to pull and replace the sucker rod.
Mill Systems and Sales. The Company engineers and fabricates inspection equipment for steel
mills, which it sells and rents. The equipment is used for quality control purposes to detect
defects in the pipe during the high-speed manufacturing process. Each piece of mill inspection
equipment is designed to customer specifications and is installed and serviced by the Company.
Fiberglass & Composite Tubulars. When compared to conventional carbon steel and even
corrosion-resistant alloys, resin-impregnated fiberglass and other modern plastic composites often
exhibit superior resistance to corrosion. Some producers manage the corrosive fluids sometimes
found in oil and gas fields by utilizing composite or fiberglass tubing, casing and line pipe in
the operations of their fields. In 1997, the Company acquired Fiber Glass Systems, a leading
provider of high pressure fiberglass tubulars used in oilfield applications, to further serve the
tubular corrosion prevention needs of its customers. Fiber Glass Systems has manufactured
fiberglass pipe since 1968 under the name Star®, and was the first manufacturer of
high-pressure fiberglass pipe to be licensed by the API in 1992. Through acquisitions and
investments in technologies, the Company has extended its fiberglass and composite tubing offering
into industrial and marine applications, in addition to its oilfield market.
Coiled Tubing. Coiled tubing provides a number of significant functional advantages over the
principal alternatives of conventional drill pipe and workover pipe. Coiled tubing allows faster
tripping, since the coiled tubing can be reeled quickly on and off a drum and in and out of a
wellbore. In addition, the small size of the coiled tubing unit compared to an average workover rig
or drilling rig reduces preparation time at the well site. Coiled tubing permits a variety of
workover and other operations to be performed without having to pull the existing production tubing
from the well and allows ease of operation in horizontal or highly deviated wells. Thus, operations
using coiled tubing can be performed much more quickly and, in many instances, at a significantly
lower cost. Finally, use of coiled tubing generally allows continuous production of the well,
eliminating the need to temporarily stop the flow of hydrocarbons. As a result, the economics of a
workover are improved because the well can continue to produce hydrocarbons and thus produce
revenues while the well treatments are occurring. Continuous production also reduces the risk of
formation damage which can occur when the flow of fluids is stopped or isolated. NOV designs,
manufactures, and sells coiled tubing under the Quality Tubing brand name at its mill in Houston,
Texas.
Pipeline Inspection. In-service inspection services for oil and gas pipelines identify anomalies
in pipelines without removing or dismantling the pipelines or stopping the product flow, giving
customers a convenient and cost-effective method of identifying potential defects. The Petroleum
Services & Supplies group inspects pipelines by launching a sophisticated survey instrument into
the pipeline. Propelled by the product flow, the instrument uses electromagnetics, ultrasonics, and
mechanical measurements received on digital and analog media to monitor the severity and location
of internal and external pitting-type corrosion as well as other mechanical anomalies in the
pipeline, providing a basis for evaluation and repair by the customer. Once the test is complete,
the survey instrument is returned to the Company, refurbished and used for future pipeline
inspections.
Customers and Competition. Customers for the Petroleum Services & Supplies tubular services
include major and independent oil and gas companies, national oil companies, drilling and workover
contractors, oilfield equipment and product distributors and manufacturers, oilfield service
companies, pipeline operators, steel mills, and other industrial companies. The Companys
competitors include, among others, Ameron International Corp, EDO Corporation,
Pipeline Integrity International Ltd. (a division of General Electric), ShawCor Ltd., Smith
International, Inc., Franks International, Inc., H. Rosen Engineerng, GmbH; T.D. Williamson, Inc.;
Baker Hughes; Diascan; Magpie; Weatherford; Patterson Tubular Services; and Precision Tube (a
division of Maverick Tube). In addition, the group competes with a number of smaller regional
competitors in tubular inspection. Certain foreign jurisdictions and government-owned petroleum
companies located in some of the countries in which this group operates have adopted policies or
regulations which may give local nationals in these countries certain competitive advantages.
Within the Companys corrosion control products, certain substitutes such as non-metallic tubulars,
inhibitors, corrosion resistant alloys, cathodic protection systems, and non-metallic liner systems
also compete with the Companys products. Management believes that the principal competitive
factors affecting this business are performance, quality, reputation, customer
service, availability of products, spare parts, and consumables, and breadth of product line and
price.
Downhole Tools. NOV designs, manufacturers and services a wide array of downhole motors used in
straight hole, directional, slim hole, and coiled tubing drilling applications. These motors are
sold or leased under the brand names TrudrillTM and VectorTM. This business
also maintains a wide variety of motor power sections, which it incorporates into its own motors
and also sells to third parties. Downhole drilling motors utilize hydraulic horsepower from the
drilling fluid pumped down the drill stem to develop torque at the bit. Motors are capable of
achieving high rotary velocities than can generally be achieved using conventional surface rotary
equipment. Motors are often used in conjunction with high speed PDC bits to improve rates of
penetration.
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The Downhole Tools group also manufactures and sells drilling jars and fishing tools, which are
marketed under the GriffithTM and BownTM brand names. Drilling jars are
placed in the drill string, where they can be used to generate a sudden, jarring motion to free the
drill string should it become stuck in the wellbore during the drilling process. This jarring
motion is generated using hydraulic and/or mechanical force provided at the surface. In the event
that a portion of the drill string becomes stuck and cannot be jarred loose, fishing tools are run
into the wellbore on the end of the drill string to retrieve the portion that is stuck.
Recently, the Downhole Tools business introduced an electronic jar placement program that
determines the optimum jar placement in the drill string as well as the effects of hole angle, hole
curvature, and frictional drag on the activation of the drilling jar. This program has proven
suitable for straight, directional, and horizontal wellbore analysis, and improves the overall
efficiency of the drilling process.
Solids Control. The solids control product line uses a variety of technologies to separate drill
cuttings from drilling fluids, and to transport, dry and refine drill cuttings for safe disposal
under the Brandt brand name. The Company believes the regulatory and industry trends toward
minimizing the environmental impact of drilling operations in a number of environmentally sensitive
oil and gas producing regions will lead to greater demand for solids control products and closed
loop drilling systems. A closed loop drilling system is a solids control system in which the
drilling mud is reconditioned and recycled throughout the drilling process on the rig itself. The
Company further believes the trend towards more technically complex drilling, including highly
deviated directional wells and slim-hole completions, will favorably impact the demand for solid
controls technology because of its ability to reduce costly downhole problems. As environmental
constraints are increased and as awareness of environmental protection grows, the Company believes
that its drill cuttings separation and treating processes will experience increased demand.
The Company has a history of introducing new solids control products and services obtained both
through its internal development and through acquiring or licensing technologies from others. A
shale shaker is the primary device on a drilling rig for removing drill solids from drilling mud.
The Company also provides screens which are mounted on shale shakers and act as a filter.
Screens are consumables which must be replaced every several days. The Company recycles certain
screen components for reuse.
In 1998, the Company initiated operations with a proprietary unit which removes hydrocarbons from
drill cuttings using heat through a process called Thermal Desorption. The processed cuttings are
usually rendered inert and can be disposed of with minimal environmental impact. The Company has
commenced operation of additional thermal desorption units in South America and Africa, and
acquired the thermal desorption operations of Maersk Contractors Environmental Division in Scotland
and Kazakhstan in 2003. The Company acquired Recovery Systems, Ltd., a provider of thermal
desorption cuttings processing services in Lowestoft, England, in 2004.
The group manufactures conventional and linear motion shale shakers and shale shaker screens, high
speed and conventional centrifuges, desanders (which remove large drill solids from drilling mud),
desilters (which remove small drill solids from drilling mud), degassers (which remove air and
gasses from drilling mud) and closed loop drilling fluids systems at its facilities in Conroe,
Texas; Houston, Texas; Aberdeen, Scotland; Leduc, Alberta; and Trinidad.
Instrumentation. The Companys Instrumentation business provides drilling rig operators real
time measurement and monitoring of critical parameters required to improve rig safety and
efficiency. Systems are both sold and rented, and are typically comprised of several sensors placed
throughout the rig to measure parameters such as weight on bit, hookload, standpipe pressure, mud
pump strokes, drilling mud levels, torque, and others, all networked back to a central command
station for review, recording and interpretation. Additionally, the rig instrumentation packages
typically provide multiple CRT screens around the rig for various rig personnel to perform
individual jobs more effectively, and cameras for certain areas to permit remote monitoring. The
Company offers proprietary touch-screen displays, interpretive software, and data archival and
retrieval capabilities. In 1999, the Company introduced its RigSense product, which
combines leading hardware and software technologies into an integrated drilling rig package. This
product permits access of drilling data from offsite locations, enabling company personnel to
monitor drilling operations from an office environment, through a secure link.
Pumps & Expendables. The Companys Pumps & Expendables business designs, manufactures, and sells
pumps that are used in oil and gas drilling operations and production applications. These pumps
include reciprocating, centrifugal, and progressive cavity pumps. (High pressure mud pumps are
sold within the Rig Technology segment.) These pumps are sold as individual units and fabricated
into complete unitized packages with drivers, controls and piping. This group also manufactures
fluid end expendables (liners, valves, pistons, and plungers) fluid end modules, and a complete
line of dies and inserts for pipe handling. The group offers popular industry brand names like
Wheatley, Gaso, and Omega reciprocating pumps, acquired in September of 2000; Halco Centrifugal
Pumps, acquired in January of 2002; Petroleum Expendable Products (PEP), acquired in May of 1997;
and Phoenix Energy Products, acquired in 1998.
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The group, through its Mono/Monoflo business, is also a worldwide leader in the design and
manufacture of a wide range of progressive cavity pumps, grinders and screens used in various
industrial applications. Mono/Monoflo also manufactures a broad range of oilfield products which
include fluid transfer, artificial lift and power sections.
The group manufactures its pump products in Houston, Odessa and Marble Falls, Texas; Tulsa and
McAlester, Oklahoma; Scott, Louisiana; Manchester, England; and Melbourne, Australia.
Customers and Competition. The primary customers drilling services offered by the Petroleum
Services & Supplies group include drilling contractors, well servicing companies, major and
independent oil and gas companies, and national oil companies. Competitors in drilling services
include NQL Energy Services; Smith International (SWACO); Derrick Manufacturing Corp.; Fluid
Systems; Oil Tools Pte. Ltd; Peak Energy Services, Ltd.; Petron Industries, Inc.; Epoch (a division
of Nabors Industries); Pason Systems, Inc.; Robbins & Myers; Kem-tron, Inc.; Double Life
Corporation, Inc. and a number of regional competitors. The Petroleum Services & Supplies group
sells drilling services into highly competitive markets. Management believes that on-site service
is becoming an increasingly important competitive element in this market, and that
the principal competitive factors affecting the business are performance,
quality, reputation, customer service, product availability and technology, breadth of product line
and price.
Distribution Services
Through its network of over 150 locations worldwide, the Distribution Services group provides
supply chain management services to drilling contractors and operators around the world. This
group stocks and sells consumables (MRO) and spare parts that are needed throughout the drilling,
completion and production process. The supplies and equipment stocked by our distribution service
centers vary by location. Each distribution point generally offers a large line of oilfield
products including valves, fittings, flanges, spare parts for oilfield equipment and miscellaneous
expendable items. With the addition of Corlac Equipment LTD in November of 2003, Distribution
Services expanded their participation in the international production equipment market.
NOVs e-Distribution solutions leverage the flexible infrastructure of SAP to extend the
customers investment in systems and address the total cost of ownership by streamlining the
acquisition process from procurement to payment, by digitally managing approval routing and
workflow, and by providing robust reporting functionality.
Approximately three-quarters of the Distribution Services groups sales in 2005 were in North
America. The remainder comes from key international markets in the North Sea, Middle East, South
America and the Far East.
Strategically the group continued to expand its alliances with oil and gas companies and certain
drilling contractors to increase its revenues in 2005. Additionally the group seeks to leverage
its extensive purchasing power to reduce the costs of the goods it purchases. The group initiated
a number of new vendor relationships with Chinese suppliers in 2005.
Customers and Competition. The primary customers for Distribution Services include drilling
contractors, well servicing companies, major and independent oil and gas companies, and national
oil companies. Competitors in Distribution Services include Wilson Supply (a division of Smith
International), CE Franklin, and a number of regional competitors.
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2005 Acquisitions and Other Investments
In 2005, the Company made the following acquisitions and outside investments:
Operating | Date of | |||||
Acquisition | Form | Segment | Transactions | |||
Comprehensive Power, Inc.
|
Minority Interest | Rig Technology | March 2005 | |||
Petroleum Services & | ||||||
Varco International, Inc.
|
Stock | Supplies/Rig Technology | March 2005 | |||
DrillLogic, LLC
|
Stock | Petroleum Services & Supplies | June 2005 | |||
Hebei Huayouyiji-Tuboscope Coating Co, Ltd
|
Joint Venture | Petroleum Services & Supplies | April 2005 | |||
Threading business of Turner FLP
Holdings, LTD.
|
Asset | Petroleum Services & Supplies | September 2005 | |||
WellTronics, LP
|
Asset | Petroleum Services & Supplies | October 2005 | |||
Smart Screen Systems, Inc.
|
Convertible Note | Petroleum Services & Supplies | November 2005 | |||
Oilfield Techno Equipment, Ltd.
|
Stock | Rig Technology | November 2005 | |||
Roil Trade s.r.o.
|
License | Petroleum Services & Supplies | April 2005 |
Excluding the Varco International, Inc. acquisition, the Company paid an aggregate purchase price
of $20.7 million ($16.0 million in cash and $4.7 million of notes payable) for acquisitions and
outside investments in 2005. See Note 3 of the Notes to the Consolidated Financial Statements for
information regarding the Varco acquisition.
Seasonal Nature of the Companys Business
Historically, the level of some of the Companys businesses has followed seasonal trends to some
degree. In general the Rig Technology group has not experienced significant seasonal fluctuation.
However, there can be no guarantee that seasonal effects will not influence future sales in this
segment.
In Canada, the Petroleum Services & Supplies segment has typically realized high first quarter
activity levels, as operators take advantage of the winter freeze to gain access to remote drilling
and production areas. In past years, certain businesses within Petroleum Services & Supplies have
declined during the second quarter due to warming weather conditions which resulted in thawing,
softer ground, difficulty accessing drill sites, and road bans that curtailed drilling activity
(Canadian Breakup). However, these businesses have typically rebounded in the third and fourth
quarter. This has also been the case with Distribution Services. Petroleum Services & Supplies
activity in both the United States and Canada sometimes increases during the third quarter and then
peaks in the fourth quarter as operators spend the remaining drilling and/or production capital
budgets for that year. Petroleum Services & Supplies revenues in the Rocky Mountain region
sometimes decline in the late fourth quarter or early first quarter due to harsh winter weather.
Within Petroleum Services & Supplies, the Pipeline Inspection business has typically experienced
reduced activity during the first quarter of the calendar year. The high winter demand for gas and
petroleum products in the northern hemisphere and the consequent curtailment of pipeline
maintenance and inspection programs often results in less opportunity to perform pipeline
inspection during this time. The segments fiberglass and composite tubulars business in China has
typically declined in the first quarter due to the impact of weather on manufacturing and
installation operations, and due to business slow downs associated with the Chinese New Year.
The Company anticipates that the seasonal trends described above will continue. However, there can
be no guarantee that spending by the Companys customers will continue to follow patterns seen in
the past or that spending by other customers will remain the same as in prior years.
Marketing & Distribution Network
Substantially all of our Rig Technology capital equipment and spare parts sales, and a large
portion of our smaller pumps and parts sales, are made through our direct sales force and
distribution service centers. Sales to foreign state-owned oil companies are typically made in
conjunction with agent or representative arrangements. Products within our Petroleum Service &
Supplies segment are rented and sold worldwide through our own sales force and through commissioned
representatives. Distribution Services sales are made through our network of distribution service
centers. Customers for our products and services include drilling and other service contractors,
exploration and production companies, supply companies and nationally owned or controlled drilling
and production companies.
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The Rig Technology segments customers include drilling contractors, shipyards and other rig
fabricators, well servicing companies, national oil companies, major and independent oil and gas
companies, supply stores, and pipe-running service providers. Demand for its products is strongly
dependent upon capital spending plans by oil and gas companies and drilling contractors, and the
level of oil and gas well drilling activity. Rig Technology purchases can represent significant
capital expenditures, and are often sold as part of a rig fabrication or major rig refurbishment
package. Sometimes these packages cover multiple rigs, and often the Company bids jointly with
other related product and services providers, such as rig fabrication yards and rig design firms.
The Petroleum Services & Supplies groups customers for tubular services include major and
independent oil and gas companies; national oil companies; oilfield equipment and product
distributors and manufacturers; drilling and workover contractors; oilfield service companies;
pipeline operators; pipe mills; manufactures and processors; and other industrial companies.
Certain tubular inspection and tubular coating products and services often are incorporated as a
part of a tubular package sold by tubular supply stores to end users.
The Company primarily
has direct operations in the international marketplace, but operates through agents in certain
markets.
The Petroleum Services & Supplies groups customers for drilling services are predominantly major
and independent oil and gas companies; national oil companies; drilling contractors; well servicing
companies; providers of drilling fluids; and other oilfield service
companies. This group operates sales and distribution facilities at strategic locations worldwide to
service areas with high drilling activity. Strategically located service and engineering facilities
provide specialty repair and maintenance services to customers. Sales of capital equipment are
sometimes made through rig fabricators, and often are bid as part of a rig fabrication package or
rig refurbishment package. Sometimes these packages cover multiple rigs, and often the Company bids
jointly with other related service providers.
Distribution Services sales are made through our network of distribution service centers. Customers
for our products and services include drilling and other service contractors, exploration and
production companies, supply companies and nationally owned or controlled drilling and production
companies.
The Companys foreign operations, which include significant operations in Canada, Europe, the Far
East, the Middle East and Latin America, are subject to the risks normally associated with
conducting business in foreign countries, including foreign currency exchange risks and uncertain
political and economic environments, which may limit or disrupt markets, restrict the movement of
funds or result in the deprivation of contract rights or the taking of property without fair
compensation. Government-owned petroleum companies located in some of the countries in which the
Company operates have adopted policies (or are subject to governmental policies) giving preference
to the purchase of goods and services from companies that are majority-owned by local nationals. As
a result of such policies, the Company relies on joint ventures, license arrangements and other
business combinations with local nationals in these countries. In addition, political
considerations may disrupt the commercial relationship between the Company and such
government-owned petroleum companies. Although the Company has not experienced any significant
problems in foreign countries arising from nationalistic policies, political instability, economic
instability or currency restrictions, there can be no assurance that such a problem will not arise
in the future. See Note 15 of the Notes to the Consolidated Financial Statements for information
regarding geographic revenue information.
Research and New Product Development and Intellectual Property
The Company believes that it has been a leader in the development of new technology and equipment
to enhance the safety and productivity of drilling and well servicing processes and that its sales
and earnings have been dependent, in part, upon the successful introduction of new or improved
products. Through its internal development programs and certain acquisitions, the Company has
assembled an extensive array of technologies protected by a substantial number of trade and service
marks, patents, trade secrets, and other proprietary rights.
As of December 31, 2005, the Company held a substantial number of United States patents and had
several patent applications pending. Expiration dates of such patents range from 2006 to 2020. As
of this date, the Company also had foreign patents and patent applications pending relating to
inventions covered by the United States patents. Additionally, the Company maintains a substantial
number of trade and service marks and maintains a number of trade secrets.
Although the Company believes that this intellectual property has value, competitive products with
different designs have been successfully developed and marketed by others. The Company considers
the quality and timely delivery of its products, the service it provides to its customers and the
technical knowledge and skills of its personnel to be more important than its intellectual property
in its ability to compete. While the Company stresses the importance of its research and
development programs, the technical challenges and market uncertainties associated with the
development and successful introduction of new products are such that there can be no assurance
that the Company will realize future revenues from new products.
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Engineering and Manufacturing
The manufacturing processes for the Companys products generally consist of machining, welding and
fabrication, heat treating, assembly of manufactured and purchased components and testing. Most
equipment is manufactured primarily from alloy steel, and the availability and price of alloy steel
castings, forgings, purchased components and bar stock is critical to the production and timing of
shipments. Primary manufacturing facilities for the Rig Technology segment are located in Houston,
Galena Park, Sugarland, Conroe, Fort Worth and Pampa, Texas; Duncan and Tulsa, Oklahoma; Orange,
California; Calgary, Nisku, and Edmonton, Canada; Mexicali, Mexico; Aberdeen, Scotland;
Kristiansand, and Stavanger, Norway; Etten-Leur, the Netherlands; Carquefou, France; Singapore;
Perth, Australia; and Lanzhou, China.
The Companys Petroleum Services & Supplies segment manufactures or assembles the equipment and
products which it rents and sells to customers, and which it uses in providing services. Downhole
tools are manufactured at facilities in Houston, Texas; and Edmonton, Alberta. Solids control
equipment and screens are manufactured at facilities in Houston and Conroe, Texas; New Iberia,
Louisiana; Aberdeen, Scotland; Nisku, Alberta; Trinidad; and Macae, Brazil. Instrumentation
equipment is manufactured at Cedar Park, Texas; and Houston, Texas facilities. Pumps are
manufactured at facilities in Houston, Texas; McAlester and Tulsa, Oklahoma; Manchester, England;
and Melbourne, Australia.
The group manufactures tubular inspection equipment and instrumented pipeline inspection tools at
its Houston, Texas facility for resale, and renovates and repairs equipment at its manufacturing
facilities in Houston, Texas; Bordon, England; Celle, Germany; Nisku, Alberta and Aberdeen,
Scotland. Fiberglass and composite tubulars and fittings are manufactured at facilities in San
Antonio, Texas; Big Spring, Texas; Little Rock, Arkansas; Tulsa, Oklahoma; Wichita, Kansas; and
Harbin and Suzhou, China facilities, while tubular coatings are manufactured in its Houston, Texas
facility, or through restricted sale agreements with third party manufacturers.
Certain of the Companys manufacturing facilities and certain of the Companys products have
various certifications, including, ISO 9001, API and ASME.
Raw Materials
The Company believes that materials and components used in its servicing and manufacturing
operations and purchased for sales are generally available from multiple sources. The prices paid
by the Company for its raw materials may be affected by, among other things, energy, steel and
other commodity prices; tariffs and duties on imported materials; and foreign currency exchange
rates. The Company experienced higher steel prices and greater difficulty securing necessary steel
supplies in 2004 and 2005 than it experienced during the preceding several years. The Company has
generally been successful in its effort to mitigate the financial impact of higher raw materials
costs on its operations by applying surcharges to and adjusting prices on the products it sells.
However, higher prices and lower availability of steel and other raw material the Company uses in
its business may adversely impact future periods.
Backlog
The Company monitors its backlog of orders within its Rig Technology group to guide its planning.
Backlog includes orders greater than $250 thousand for most items and orders for wireline units in
excess of $75 thousand, and which require more than three moths to manufacture and deliver.
Backlog measurements are made on the basis of written orders which are firm, but are generally
cancelable by the customer. Most require reimbursement to the Company for costs incurred in such
an event. There can be no assurance that the backlog amounts will ultimately be realized as
revenue, or that the Company will earn a profit on backlog work. Our backlog for equipment at
recent year-ends has been:
December 31, 2005
|
$2,299 million | |
December 31, 2004
|
605 million * | |
December 31, 2003
|
339 million * |
* | excludes Varco backlog |
Employees
At December 31, 2005, the Company had a total of 21,610 employees, of which 2,631 were temporary
employees. Approximately 134 employees in the Companys fiberglass tubulars plant in Little Rock,
Arkansas, and 91 employees of the Companys downhole tools product line, are subject to collective
bargaining agreements. Additionally, certain of the Companys employees in certain foreign
locations, principally Norway and Argentina, are subject to collective bargaining agreements.
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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 oil and gas industry, which is volatile.
The oil and gas industry historically has experienced significant volatility. Demand for our
services and products depends primarily upon the number of oil rigs in operation, the number of oil
and gas wells being drilled, the depth and drilling conditions of these wells, the volume of
production, the number of well completions, capital expenditures of other oilfield service
companies and the level of workover activity. Drilling and workover activity can fluctuate
significantly in a short period of time, particularly in the United States and Canada. The
willingness of oil and gas operators to make capital expenditures to explore for and produce oil
and natural gas and the willingness of oilfield service companies to invest in capital equipment
will continue to be influenced by numerous factors over which we have no control, including:
| the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits, the level of production by non-OPEC countries and worldwide demand for oil and gas; | ||
| level of production from known reserves; | ||
| cost of exploring for and producing oil and gas; | ||
| level of drilling activity and drilling rig dayrates; | ||
| worldwide economic activity; | ||
| national government political requirements; | ||
| development of alternate energy sources; and | ||
| environmental regulations. |
If there is a significant reduction in demand for drilling services, in cash flows of drilling
contractors, well servicing companies, or production companies or in drilling or well servicing rig
utilization rates, then demand for the products and services of the company will decline.
Volatile oil and gas prices affect demand for our products.
Oil and gas prices have been volatile since 1990. 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 $25-65 per barrel since 2000. Spot gas prices generally ranged between
$1.80-2.60 per mmbtu of gas from 1991 through 1999, then experienced severe spikes into the $10
range in 2001 and 2003. Absent occasional spikes and dips due to imbalances in supply and demand,
prices have generally ranged between $6.00-10.00 per mmbtu during the last two years.
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.
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 their current major product lines. These
competitors may have greater financial, technical, manufacturing and marketing resources than
us, and may be in a better competitive position. The following competitive
actions can each affect our revenues and earnings:
| price changes; | ||
| new product and technology introductions; and | ||
| improvements in availability and delivery. |
In addition, certain foreign jurisdictions and government-owned petroleum companies located in some
of the countries in which we operate have adopted policies or regulations which may give local
nationals in these countries competitive advantages. Competition in our industry could lead to
lower revenues and earnings.
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We
have aggressively expanded its businesses, and intends to maintain an
aggressive growth strategy.
We have aggressively expanded and grown its 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 combined 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 combined 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 you
that we will realize expected earnings growth or that earnings in any particular quarter will not
fall short of either a prior fiscal quarter or investors expectations. The following factors, in
addition to others not listed, may affect our quarterly operating results in the future:
| fluctuations in the oil and gas industry; | ||
| competition; | ||
| the ability to service the debt obligations of the combined company; | ||
| the ability to identify strategic acquisitions at reasonable prices; | ||
| the ability to manage and control operating costs of the combined company; | ||
| fluctuations in political and economic conditions in the United States and abroad; and | ||
| the ability to protect our intellectual property rights. |
There are risks associated with our presence in international markets, including political or
economic instability and currency restrictions.
Approximately
56% of our revenues in 2005 were derived from operations outside the
United States. Our foreign operations include significant operations in
Europe, the Middle East, Africa, Southeast Asia, South 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.
An impairment of goodwill could reduce the combined companys earnings.
We recorded approximately $2.1 billion of goodwill on its consolidated balance
sheet as of December 31, 2005. Goodwill is recorded when the purchase price of a business exceeds
the fair market value of the tangible and separately measurable intangible net assets. Generally
accepted accounting principles requires us to test goodwill for impairment on an annual basis or
when events or circumstances occur indicating that goodwill might be impaired. If we were to
determine that any of our remaining balance of goodwill was impaired, we would record an immediate
charge to earnings with a corresponding reduction in stockholders equity and increase in balance
sheet leverage as measured by debt to total capitalization.
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
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permits for failure to comply with applicable laws and regulations. Under these circumstances, we
might be required to reduce or cease operations or conduct site remediation or other corrective
action which could adversely impact our operations and financial condition.
Our businesses expose us to potential environmental liability.
Our businesses expose us to the risk that harmful substances may escape into the environment, which
could result in:
| personal injury or loss of life; | ||
| severe damage to or destruction of property; or | ||
| environmental damage and suspension of operations. |
Our current and past activities, as well as the activities of our former divisions and
subsidiaries, could result in our facing substantial environmental, regulatory and other
liabilities. These could include the costs of cleanup of contaminated sites and site closure
obligations. These liabilities could also be imposed on the basis of one or more of the following
theories:
| negligence; | ||
| strict liability; | ||
| breach of contract with customers; or | ||
| as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case. |
We may not have adequate insurance for potential environmental liabilities.
While we maintain liability insurance, this insurance is subject to coverage limits. In addition,
certain policies do not provide coverage for damages resulting from environmental contamination. We
face the following risks with respect to our insurance coverage:
| we may not be able to continue to obtain insurance on commercially reasonable terms; | ||
| we may be faced with types of liabilities that will not be covered by our insurance; | ||
| our insurance carriers may not be able to meet their obligations under the policies; or | ||
| the dollar amount of any liabilities may exceed our policy limits. |
Even a partially uninsured claim, if successful and of significant size, could have a material
adverse effect on our consolidated financial statements.
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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 raises 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 real, 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. |
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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 waters surface to the sea floor. | |
Drill stem
|
All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items. | |
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. | |
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. | |
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 ope-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 metres, 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 metres) 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 metres) long, and have diameters as small as 2 1/2 inches (6 centimetres) and as large as 6 inches (15 centimetres). | |
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 |
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since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing. | ||
Kelly spinner
|
A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up. | |
Kick
|
An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur. | |
Making-up
|
1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time). | |
Manual tongs (Tongs)
|
The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque. | |
Master bushing
|
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing. | |
Motion compensation equipment |
Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig. | |
Mud pump
|
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig. | |
Plug gauging
|
The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards. | |
Pressure control equipment
|
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 |
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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 units drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection. | |
Solids
|
See Cuttings | |
Spinning wrench
|
Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections. | |
Spinning-in
|
The rapid turning of the drill stem when one length of pipe is being joined to another. Spinning-out refers to separating the pipe. | |
Stand
|
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 metres) long (three lengths of drill pipe screwed together), or a thribble. | |
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. | |
Top drive
|
A device similar to a power swivel that is used in place of the rotary table to turn the drill |
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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 or unanticipated complications while drilling a well. These cost are often referred to as contingency costs during the planning phase of a well. | |
Well completion
|
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths. | |
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 oilwell to try to increase production oilwell 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.
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ITEM 2. PROPERTIES
The Company owned or leased approximately 557 facilities worldwide as of December 31, 2005,
including the following principal manufacturing, service, distribution and administrative
facilities:
Building | ||||||||||||||||||
Size | Property | Lease | ||||||||||||||||
(Square | Size | Owned/ | Termination | |||||||||||||||
Location | Description | Feet) | (Acres) | Leased | Date | |||||||||||||
Rig
Technology: |
||||||||||||||||||
Lanzhou, China |
Mfg. Plant (Drilling Equipment) | 1,248,000 | Owned | |||||||||||||||
Houston, Texas |
West Little York Manufacturing | 619,000 | 34.00 | Owned | ||||||||||||||
Facility, Repair, Service, | ||||||||||||||||||
Administrative & Sales Offices | ||||||||||||||||||
Pampa, Texas |
MFG. Plant | 548,000 | 400 | Owned | ||||||||||||||
Houston, Texas |
Mfg. Plant (Drilling Machinery and | 417,000 | Leased | Various | ||||||||||||||
Equip) | ||||||||||||||||||
Carquefou, France |
Mfg. Plant (Offshore Equipment) | 213,000 | Owned | |||||||||||||||
Houston, Texas |
Mfg. Plant (Braking Systems) | 200,000 | 24 | Owned | ||||||||||||||
Houston, Texas |
Mfg. Plant (Electrical Power Systems) | 184,000 | 10.5 | Owned | ||||||||||||||
Houston, Texas |
MFG Plant (Drilling Rigs and | 178,000 | Owned | |||||||||||||||
Components) | ||||||||||||||||||
Fort Worth, Texas |
Coiled Tubing Manufacturing Facility, | 167,999 | 30.92 | Leased | 01/31/14 | |||||||||||||
Warehouse, Administrative & Sales | ||||||||||||||||||
Offices | ||||||||||||||||||
Kristiansand, Norway |
Mfg. (Drilling and Offshore | 157,000 | Owned | |||||||||||||||
Equipment) | ||||||||||||||||||
Orange, California |
Manufacturing & Office Facility - 759 | 126,000 | 8.90 | Building | 04/30/12 | |||||||||||||
N. Eckhoff | Owned* | |||||||||||||||||
Aberdeen, Scotland |
Pressure Control Manufacturing, | 107,974 | 7.50 | Leased | 08/31/19 | |||||||||||||
Administrative & Sales | ||||||||||||||||||
Molde, Norway |
Mfg. (Marine Handling Equipment) | 78,000 | Owned | |||||||||||||||
Mexicali, Mexico |
Mfg. Plant | 76,402 | Leased | 04/01/14 | ||||||||||||||
Calgary, Alberta, |
Mfg. (Coiled Tubing and Wireline | |||||||||||||||||
Canada |
Units) | 76,000 | Owned | |||||||||||||||
Etten-Leur,
Netherlands |
Mfg. Plant/Sales (Drilling Equipment) | 75,000 | 6.00 | Owned | ||||||||||||||
Duncan, Oklahoma |
Nitrogen Units Manufacturing | 67,600 | 13.28 | Owned | ||||||||||||||
Facility, Warehouse & Offices | ||||||||||||||||||
Houston, Texas |
Brittmore Shaffer Repair & Service | 66,500 | 5.79 | Leased | 11/01/11 | |||||||||||||
Facility | ||||||||||||||||||
Aberdeen, Scotland |
Systems & Shaffer Sales, Service & | 63,000 | 6.00 | Owned | ||||||||||||||
Distribution Facility | ||||||||||||||||||
Edmonton, Alberta,
Canada |
Mfg. (Drilling Machinery and Equip.) | 61,000 | Owned | |||||||||||||||
Nisku, Alberta,
Canada |
Mfg. (Drilling Machinery and Equip.) | 60,000 | Owned | |||||||||||||||
Calgary, Alberta, |
Coiled Tubing Manufacturing Facility, | |||||||||||||||||
Canada |
Administrative & Sales Offices | 48,040 | 2.52 | Owned | ||||||||||||||
Stavanger, Norway |
Drilling Equipment Work Shop, | 41,333 | 0.42 | Leased | 06/01/09 | |||||||||||||
Warehouse & Customer Service Center | ||||||||||||||||||
Tulsa, Oklahoma |
Pumping Manufacturing Facility, | 40,700 | 4.47 | Leased | 12/31/07 | |||||||||||||
Warehouse & Offices | ||||||||||||||||||
Tuas, Singapore |
Coiled Tubing & Wireline Products | 35,300 | 1.50 | Building | 04/15/14 | |||||||||||||
Manufacturing & Administrative | Owned* | |||||||||||||||||
Facility | ||||||||||||||||||
Singapore |
Systems Offices, Service & | 35,079 | 1.20 | Building | 07/01/40 | |||||||||||||
Distribution Facility | Owned* |
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Building | ||||||||||||||||||
Size | Property | Lease | ||||||||||||||||
(Square | Size | Owned/ | Termination | |||||||||||||||
Location | Description | Feet) | (Acres) | Leased | Date | |||||||||||||
Orange, California |
Administrative Offices743 N. Eckhoff | 35,000 | 1.60 | Leased | 04/30/12 | |||||||||||||
Coiled Tubing & Nitrogen Units | ||||||||||||||||||
Great Yarmouth, |
Manufacturing, Administrative & Sales | |||||||||||||||||
England |
Offices | 29,000 | 1.70 | Leased | 08/22/11 | |||||||||||||
Petroleum Services & Supplies: | ||||||||||||||||||
Al Khobar, Saudi |
Reclamation, Inspection Facility & | |||||||||||||||||
Arabia |
Offices | 340,203 | 8.00 | Leased | 11/30/10 | |||||||||||||
Houston, Texas |
Coiled Tubing Manufacturing Facility, | 101,250 | 14.00 | Owned | ||||||||||||||
Warehouse and Offices | ||||||||||||||||||
Houston, Texas |
Sheldon Road: Inspection Facility | 335,993 | 192.00 | Owned | ||||||||||||||
Houston, Texas |
Holmes Road Complex: Manufacturing, | 300,000 | 50.00 | Owned | ||||||||||||||
Warehouse, Corporate Offices, Coating | ||||||||||||||||||
Manufacturing Plant & Pipeline | ||||||||||||||||||
Services | ||||||||||||||||||
Fiberglass Tubular Manufacturing | ||||||||||||||||||
Little Rock, |
Plant, R&D Lab, Administrative | |||||||||||||||||
Arkansas |
Offices | 262,784 | 44.00 | Leased | Yr. to Yr. | |||||||||||||
Cedar Park, Texas |
Instrumentation Manufacturing | 260,000 | 40.00 | Owned | ||||||||||||||
Facility, Administrative & Sales | ||||||||||||||||||
Offices | ||||||||||||||||||
Manchester, England |
Mfg. (Pumps and expendable parts) | 244,000 | Owned | |||||||||||||||
Yopal, Colombia |
Inspection and Solids Control | 215,280 | 4.94 | Owned | ||||||||||||||
Warehouse & Storage | ||||||||||||||||||
Sand Springs,
Oklahoma |
Fiberglass Tubular Manufacturing Plant | 189,173 | 6.50 | Owned | ||||||||||||||
Amelia, Louisiana |
Coating Plant & Inspection Facility | 179,574 | 84.00 | Leased | 12/31/16 | |||||||||||||
Houston, Texas |
Coating Plant & Inspection Facility | 168,683 | 49.00 | Owned | ||||||||||||||
Tulsa, Oklahoma |
Mfg. (Pumps and expendable parts) | 165,000 | Owned | |||||||||||||||
Edmonton, Alberta,
Canada |
Mfg. (Downhole Tools) | 162,000 | Owned | |||||||||||||||
Conroe, Texas |
Solids Control & Pressure Control | 160,000 | 30.49 | Owned | ||||||||||||||
Manufacturing Facility, Warehouse, | ||||||||||||||||||
Administrative & Sales Offices & | ||||||||||||||||||
Engineering Labs | ||||||||||||||||||
Wichita, Kansas |
Fiberglass Tubular Manufacturing Plant | 129,746 | 15.00 | Owned | ||||||||||||||
Nisku, Alberta, |
Trucking, Rod Plant, Inspection & | |||||||||||||||||
Canada |
Storage Facility | 121,545 | 155.00 | Owned | ||||||||||||||
McAlester, Oklahoma |
Mfg. (Pumps) | 120,000 | Owned | |||||||||||||||
Nisku, Alberta, |
Coating Plant, Inspection & Drill | |||||||||||||||||
Canada |
Pipe Facility | 114,000 | 47.00 | Owned | ||||||||||||||
Amelia, Louisiana |
Coating Plant, Inspection & Storage | 102,000 | 90.00 | Building | 05/30/06 | |||||||||||||
Facilities | Owned* | |||||||||||||||||
Casper, Wyoming |
Inspection Facility | 91,720 | 29.00 | Owned | ||||||||||||||
Midland, Texas |
Coating Plant | 87,000 | 25.00 | Owned | ||||||||||||||
Houston, Texas |
Mfg. (Downhole Tools) | 86,175 | Leased | 12/31/18 | ||||||||||||||
Houston, Texas |
Highway 90: Coating Plant | 83,000 | 43.00 | Leased | 07/31/11 | |||||||||||||
San Antonio, Texas |
Fiberglass Tubular Manufacturing | 82,700 | 19.57 | Owned | ||||||||||||||
Plant, | ||||||||||||||||||
R & D Lab, Administrative Offices | ||||||||||||||||||
Big Spring, Texas |
Fiberglass Tubular Manufacturing | 78,600 | 12.00 | Owned | ||||||||||||||
Plant & Administrative Offices | ||||||||||||||||||
Aberdeen, Scotland |
Solids Control Manufacturing Facility | 77,400 | 6.25 | Owned | ||||||||||||||
Assembly, Administrative & Sales | ||||||||||||||||||
Houston, Texas |
Engineering/Technical Research Center | 76,000 | 6.00 | Owned | ||||||||||||||
Bogota, Colombia |
Solids Control & Inspection Yard & | 69,966 | Leased | 08/01/06 | ||||||||||||||
Warehouse | ||||||||||||||||||
Navasota, Texas |
Coating Plant, Inspection Pipe Storage | 65,000 | Building | 06/30/13 | ||||||||||||||
Owned* | ||||||||||||||||||
Marble Falls, Texas |
Mfg. (Expendable parts) | 65,000 | Owned | |||||||||||||||
MDT, Shaffer, Chimo, Alberta | 64,056 | 4.60 | Owned | |||||||||||||||
Leduc, Alberta, |
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Building | ||||||||||||||||||
Size | Property | Lease | ||||||||||||||||
(Square | Size | Owned/ | Termination | |||||||||||||||
Location | Description | Feet) | (Acres) | Leased | Date | |||||||||||||
Canada |
Instruments, Varco Services & | |||||||||||||||||
Warehouse Facility | ||||||||||||||||||
Su Zhou, Peoples
Republic of China |
Fiberglass Tubular Manufacturing Plant | 60,000 | 4.00 | Owned | ||||||||||||||
Lone Star, Texas |
Inspection Facility | 56,700 | 80.00 | Owned | ||||||||||||||
Neiva, Columbia |
Inspection Yard & Warehouse | 54,898 | 1.26 | Leased | 09/30/06 | |||||||||||||
Aberdeen, Scotland |
Inspection Facility, Coating Plant, | 53,425 | 10.00 | Owned | ||||||||||||||
Manufacturing, Administrative & Sales | ||||||||||||||||||
Coevorden, |
Inspection Reclamation & Repair | |||||||||||||||||
Netherlands |
Facility | 53,361 | 2.00 | Leased | 12/04/09 | |||||||||||||
Harvey, Louisiana |
Coating Plant & Inspection Facility | 53,000 | 7.00 | Owned & | 09/30/07 | |||||||||||||
Leased | ||||||||||||||||||
Houston, Texas |
Mfg. (Pumps and expendable parts) | 51,000 | Leased | 12/31/10 | ||||||||||||||
Tuas, Singapore |
Coating Plant & Inspection Facility | 50,644 | 8.00 | Building | 06/09/09 | |||||||||||||
Owned* | ||||||||||||||||||
Odessa, Texas |
Coating Plant & Inspection Facility | 45,332 | 10.00 | Owned | ||||||||||||||
Little Rock,
Arkansas |
Fiberglass Tubular Manufacturing Plant | 45,000 | Leased | 10/01/09 | ||||||||||||||
Berlaimont, France |
Coating Plant | 44,000 | 16.00 | Owned | ||||||||||||||
Celle, Germany |
Inspection Facility, Administrative & | 43,560 | 12.00 | Building | 2049 | |||||||||||||
Engineering Offices | Owned* | |||||||||||||||||
Casper, Wyoming |
Inspection Facility | 41,030 | 40.00 | Owned | ||||||||||||||
Edmond, Oklahoma |
Coating Plant | 40,000 | 19.00 | Owned | ||||||||||||||
Farmington, New
Mexico |
Inspection Storage Facilities | 37,725 | 50.00 | Leased | 03/31/14 | |||||||||||||
Odessa, Texas |
Inspection Facility | 33,910 | 50.00 | Owned | ||||||||||||||
Edmonton, Alberta, |
Sucker Rod Inspection & Oilwell | |||||||||||||||||
Canada |
Engine Reclamation | 32,550 | 10.00 | Leased | 12/31/05 | |||||||||||||
Distribution: |
||||||||||||||||||
Houston, Texas |
Distribution and Warehouse | 84,000 | Owned | |||||||||||||||
Corporate: |
||||||||||||||||||
Houston, Texas |
Corporate Administrative Office | 115,000 | Office Building | Leased | 10/31/15 | |||||||||||||
Houston, Texas |
Adminstrative Offices | 48,000 | Office Building | Leased | 10/31/15 |
* | Building owned but real estate leased. |
We own or lease 214 repair and manufacturing facilities that refurbish and manufacture new
equipment and parts, and approximately 154 distribution service centers, and 135 service centers
that provide inspection and equipment rental worldwide.
We own undeveloped acreage next to several of our facilities, including over 100 acres of
undeveloped property located in Houston, Texas. Machinery, equipment, buildings, and other
facilities owned and leased are considered by management to be adequately maintained and adequate
for our operations.
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
statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the quarter ended December 31, 2005.
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PART II
ITEM
5. MARKET FOR REGISTRANTS 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:
2005 | 2004 | |||||||||||||||
High | Low | High | Low | |||||||||||||
1st Quarter |
50.21 | 33.23 | 30.96 | 21.77 | ||||||||||||
2nd Quarter |
48.52 | 39.74 | 31.49 | 25.76 | ||||||||||||
3rd Quarter |
67.45 | 46.70 | 34.15 | 28.43 | ||||||||||||
4th Quarter |
66.52 | 55.18 | 36.99 | 31.87 |
As of February 21, 2006, there were 799 holders of record of our common stock. Many stockholders
choose to own shares through brokerage accounts and other intermediaries rather than as holders of
record so the actual number of stockholders is unknown but significantly higher. We have never paid cash
dividends, and none are anticipated during 2006.
The
information relating to our equity compensation plans required by
Item 5 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.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31, | ||||||||||||||||||||
2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
(dollars in millions, except per share data) | ||||||||||||||||||||
Operating Data: |
||||||||||||||||||||
Revenue |
$ | 4,644.5 | $ | 2,318.1 | $ | 2,004.9 | $ | 1,521.9 | $ | 1,747.5 | ||||||||||
Operating income (1) |
476.8 | 176.0 | 164.1 | 127.7 | 189.3 | |||||||||||||||
Income before taxes |
430.0 | 138.9 | 121.8 | 106.7 | 168.0 | |||||||||||||||
Net income (1) |
$ | 286.9 | $ | 115.2 | $ | 79.7 | $ | 67.1 | $ | 104.1 | ||||||||||
Net income per share |
||||||||||||||||||||
Basic (1) |
$ | 1.83 | $ | 1.34 | $ | 0.94 | $ | 0.83 | $ | 1.29 | ||||||||||
Diluted (1) |
$ | 1.81 | $ | 1.33 | $ | 0.94 | $ | 0.82 | $ | 1.27 | ||||||||||
Other Data: |
||||||||||||||||||||
Depreciation and amortization |
$ | 114.6 | $ | 44.0 | $ | 39.2 | $ | 25.0 | $ | 38.9 | ||||||||||
Capital expenditures |
$ | 105.0 | $ | 39.0 | $ | 32.4 | $ | 24.8 | $ | 27.4 | ||||||||||
Balance Sheet Data: |
||||||||||||||||||||
Working capital |
$ | 1,811.0 | $ | 711.0 | $ | 763.0 | $ | 734.8 | $ | 631.3 | ||||||||||
Total assets |
6,678.5 | 2,576.5 | 2,213.1 | 1,942.5 | 1,471.7 | |||||||||||||||
Long-term debt, less current maturities |
835.6 | 350.0 | 594.0 | 594.6 | 300.0 | |||||||||||||||
Stockholders equity |
4,194.2 | 1,270.2 | 1,059.2 | 899.3 | 839.4 |
(1) | We adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS 142), effective January 1, 2002. The effects of not amortizing goodwill and other intangible assets in periods prior to the adoption of SFAS 142 would have resulted in net income of $115.0 million, basic earnings per common share of $1.42, and diluted earnings per common share of $1.41 for the year ending December 31, 2001. |
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ITEM 7. | MANAGEMENTS 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 500 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, provide in-service pipeline inspections, manufacture
high pressure fiberglass and composite tubing, and sell and rent advanced in-line inspection
equipment to makers of oil country tubular goods. We have a long tradition of pioneering
innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of
oil and gas operations.
Our revenues and operating results are directly related to the level of worldwide oil and gas
drilling and production activities and the profitability and cash flow of oil and gas companies and
drilling contractors, which in turn are affected by current and anticipated prices of oil and gas.
Oil and gas prices have been and are likely to continue to be volatile. See Risk Factors. We
conduct our operations through three business segments: Rig Technology, Petroleum Services &
Supplies and Distribution Services. See Item 1. Business for a discussion of each of these
business segments.
Operating Environment Overview
Our results are dependent on, among other things, the level of worldwide oil and gas drilling, well
remediation activity, the price of crude oil and natural gas, capital spending by other oilfield
service companies and drilling contractors, pipeline maintenance activity, and the worldwide oil
and gas inventory levels. Key industry indicators for the past three years include the following:
% | % | |||||||||||||||||||
2005 vs. | 2005 vs. | |||||||||||||||||||
2005* | 2004* | 2003* | 2004 | 2003 | ||||||||||||||||
Active Drilling Rigs: |
||||||||||||||||||||
U.S. |
1,381 | 1,190 | 1,032 | 16.1 | % | 33.8 | % | |||||||||||||
Canada |
458 | 369 | 372 | 24.1 | % | 23.1 | % | |||||||||||||
International |
908 | 836 | 771 | 8.6 | % | 17.8 | % | |||||||||||||
Worldwide |
2,747 | 2,395 | 2,175 | 14.7 | % | 26.3 | % | |||||||||||||
Active Workover Rigs: |
||||||||||||||||||||
U.S. |
1,354 | 1,236 | 1,130 | 9.5 | % | 19.8 | % | |||||||||||||
Canada |
654 | 615 | 350 | 6.3 | % | 86.9 | % | |||||||||||||
North America |
2,008 | 1,851 | 1,480 | 8.5 | % | 35.7 | % | |||||||||||||
West Texas Intermediate
Crude Prices (per barrel) |
$ | 56.65 | $ | 41.44 | $ | 30.89 | 36.7 | % | 83.4 | % | ||||||||||
Natural Gas Prices ($/mmbtu) |
$ | 8.83 | $ | 5.88 | $ | 5.49 | 50.2 | % | 60.8 | % |
* | 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 three years ended December 31, 2005 on a quarterly basis:
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![(BAR CHART)](https://www.sec.gov/Archives/edgar/data/0001021860/000095012906002268/h33638h3363801.gif)
Source:
Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price:
Department of Energy, Energy Information Administration (www.eia.doe.gov).
Oil and natural gas prices continued to be strong in 2005. The average price per barrel of West
Texas Intermediate Crude reached historic heights in 2005 after rising sharply throughout the first
three quarters of 2005. The 2005 average price for the year was the highest ever-annual average oil price for the year of
$56.65 per barrel, an increase of 36.7% over the average for 2004. Natural gas prices were $8.83
per mmbtu, an increase of 50.2% compared to the 2004 average. High commodity prices led to
stronger rig activity worldwide, increasing 14.7% for the full year in 2005 compared to 2004.
However, rig activity in the Gulf of Mexico suffered from two major hurricanes during the third
quarter of 2005.
At February 17, 2006 there were 1,545 rigs actively drilling in the U.S., compared to 1,471 rigs at
December 31, 2005. The company believes that current industry projections are forecasting
commodity prices to remain strong, and, as a result, U.S., Canada, and international drilling rig
activity is expected to continue at a high level. However, numerous events could significantly
alter these projections including political tensions in the Middle East, the acceleration or
deceleration of the recovery of the U.S. and world economies, a build up in the world inventory
levels, or numerous other events or circumstances.
Executive Summary
The Company generated earnings of $286.9 million, or $1.81 per fully diluted share, on reported
revenues of $4,644.5 for the year ended December 31, 2005.
On March 11, 2005, we merged with Varco. As a result, the reported financial results for 2005 do
not incorporate the results of Varco operations prior to the merger. We have presented
supplemental estimated pro forma results as if we had been merged with Varco throughout 2004 and
2005. The discussion and analysis below pertain to the results on this pro forma basis.
Additionally, our disclosures since the merger have identified transaction, integration and
stock-based compensation charges, including severance, restructuring, equipment and inventory
rationalization, and amortization of options issued to replace Varco options. The discussion of
the results that follow excludes these items, except where noted.
28
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Oil & Gas Equipment and Services Market
Activity levels and demand for our products and services improved in most of our business segments
in 2005. Demand for oil and gas continued to increase during 2005. As a result, oil and gas
prices have increased significantly over the past few years, which has led to rising levels of
exploration and development drilling in many oil and gas producing basins around the globe. The
world-wide rig count, a good indicator of oilfield activity and spending, increased 15 percent in
2005, up for the third consecutive year. Oil and gas companies have increased their levels of
investment in new oil and gas wells, to reverse the trend of declining reserves and to grow
production to satisfy the rising energy needs of the world. This has led to a level of drilling
activity not seen since the early 1980s, which has, in turn, resulted in steadily rising demand
for oilfield services over the last several quarters. Much of the new incremental drilling
activity is occurring in harsh environments and employs increasingly sophisticated technology to
find and produce reserves.
The rise in demand for drilling rigs has driven rig dayrates the amount a drilling contractor
charges per day for the use and operation of a drilling rig sharply higher over the past several
quarters, which has increased cash flows and available financing to drilling contractors. Rising
dayrates have caused many older drilling rigs to be placed back into service, and we believe that
virtually every drilling rig that can operate is now in operation. We have played an important
role in providing the equipment, consumables and services needed to reactivate many of these older
rigs. Sales of individual drilling components, some of which do not flow through our backlog,
generally trended up through the year as contractors reactivated rigs for service.
Higher utilization of drilling rigs has tested the capability of the worlds fleet of rigs, much of
which is old and of limited capability compared to newer drilling rigs. Technology has advanced
since most of the existing rig fleet was built. The industry invested little during the late
1980s and 1990s towards the purchase of new drilling equipment. However, drilling technology
progressed steadily, as we and our 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. Oil and gas producers often demand top
performance from drilling rigs, particularly at the premium dayrates that are being paid today. As
a result of this trend, we have benefited from increasing demand for new products such as our
small iron roughnecks for land rigs, and our LXT BOPs to upgrade certain rig functions to make
them safer and more efficient.
Drilling rigs are now being required by contractors to drill deeper wells, more complex wells,
highly deviated wells and horizontal wells, which require larger rigs with more capabilities.
Higher dayrates magnify the opportunity cost of rig downtime, and rigs are being pushed to maximize
revenue days for their drilling contractor owners. The drilling process effectively consumes the
mechanical components of a rig, which wear out and need periodic repair or replacement. This
process has been accelerated by the high levels of rig utilization seen throughout 2005. In
preceding years contractors could cannibalize mechanical components from their idle rigs, rather
than purchase new components. As the fleet of idle rigs has dwindled in 2005, the availability of
used components has dwindled as well, which has spurred high demand for our rig components.
Changing
methods of drilling have further benefited our business.
Increasingly, hydraulic horsepower
in addition to conventional mechanical rotary power is being used to apply torque to the drill
bit. This is done using downhole drilling motors powered by drilling fluids. We are a major
provider of downhole drilling motors and have seen demand for this application of our drilling
motors increase in 2005. This trend has also increased demand for our high pressure mud pumps,
which create the hydraulic horsepower in the drilling fluid which drive the drilling motors.
While the increasingly efficient equipment we provide has mitigated the effect, high activity
levels have increased demand for personnel in the oilfield. Consequently, we, our customers and
our suppliers have experienced wage inflation in certain markets. Hiring experienced drilling
crews has been challenging for the drilling industry; however, we believe crews generally prefer
working on newer, safer, more modern rigs. Our products which save labor and increase efficiency also
make the rig crews jobs easier, and make the rig a more desirable place to work. Experienced
crews are more likely to perform routine maintenance on rigs, and lapses in maintenance can add
additional stress on mechanical drilling machinery. Many of our products ease the routine
maintenance of rig components. Additionally, many of our products
improve the safety of drilling operations, a very important factor
for rig owners and their customers.
Finally, the increase in drilling rig dayrates has made the economics of building new rigs
compelling in many markets. For the first time in many years, the industry is actively building
land rigs and offshore rigs. Many new offshore rig construction projects were announced throughout
2005, and there are approximately 51 new jackup rigs and 21 new floating rigs being constructed
worldwide now. The available supply of offshore rigs declined during the third quarter due to the
impact of hurricanes Katrina and Rita, which seriously damaged or sunk several offshore rigs in the
Gulf of Mexico.
Segment Performance
Our Rig Technology group has been awarded many new orders for equipment for rigs being constructed
or repaired around the world, and we completed 2005 with a record backlog. Backlog nearly tripled
over the course of the year to $2.3 billion. We have
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the capability to supply up to approximately $41 million of equipment for a typical jackup rig,
more than $130 million of equipment for a new floating rig, and effectively all of a new land rig,
which range in price from less than $1 million to over $20 million. Our strategy targets the high
end of the market, emphasizing technology, quality and reliability. Most of the incremental growth
in the backlog has been for offshore drilling packages for jackup, semi-submersible and drillship
rigs being constructed or undergoing major refurbishment. The delivery of this equipment is
typically tied to the construction schedule of the rig, which can take as long as four years to
complete. As a result much of our backlog delivery extends well beyond 2006, and we have
commissioning and installation work out as far as 2010. We expect to recognize as revenue in 2006
approximately $1.3 billion of our year end $2.3 billion total backlog, but other orders received
into backlog in early 2006 may also be recognized as revenue in late 2006.
Pro forma revenues for the Rig Technology group grew $608.1 million or 35 percent, and pro forma
operating profit improved $83.4 million in 2005 from the prior year. Group operating profit in
2005 benefited from higher volumes and merger-related cost savings, offset by charges taken on two
rigs delivered to Kazakhstan, higher than expected costs on a new kingpost crane design, and higher
fourth quarter inventory, legal, and accounts receivable reserves. Rig Technology flow-through or
operating leverage defined as the increase in year-over-year pro forma operating profit divided
by the increase in year-over-year pro forma revenue was 14 percent. However, excluding the
fourth quarter reserve increases, the crane costs and Kazakhstan rig charges, the flow-through -
incremental operating profit divided by incremental revenue was 22 percent, consistent with the
our long-term expectations for the Rig Technology segment.
The high oil and gas activity levels discussed above also increased demand for our Petroleum
Services & Supplies group. Sales of composite fiberglass pipe, solids control products and
services, drilling motors and jars, mud pump expendables, coiled tubing pipe, rig instrumentation
equipment and services, and tubular coating and inspection have all benefited from the higher
levels of exploration and production investment in drilling and stimulating wells. High demand
enabled the group to increase some prices during the year, in roughly the 5 to 10 percent range.
The margin impact of price increases was mitigated somewhat by higher costs in many areas. Pro
forma revenues increased $407.2 million or 28 percent, and pro forma operating profit increased
$110.1 million in 2005 from the prior year. Flow-through of pro forma operating profit was 27
percent, slightly below our long-term expectation of 30 percent. This was due to a sharp
year-over-year decline in profitability from pipeline inspection, which experienced a downturn in
business in the U.S. in 2005 after very strong results in 2004 due to the timing of a job performed
in late 2004 rather than early 2005. Excluding the pipeline results, year-over-year flow through
for the Petroleum Services & Supplies group was 30 percent.
Our Distribution Services group also benefited from higher levels of oilfield activity, which has
spurred rising demand for the maintenance, repair and operating supplies it furnishes to the
petroleum industry. Many oil companies and drilling contractors are outsourcing their purchasing
of routine consumable items to the group, which offers greater purchasing power and sophisticated
information management techniques. Revenues increased $169.4 million or 19 percent, and operating
profit increased 57 percent the results were not affected by the Varco merger, so there are no
pro forma adjustments. The group benefited from higher sales into international locations, where
it has expanded in recent years, and from extensive sales late in the year to the Gulf of Mexico
region, to support clean-up efforts following hurricanes Katrina and Rita. Margins benefited from
improved expense management and higher supplier rebates on the greater volumes, partly offset by
lower margin sales of line pipe. Overall operating margins improved 100 basis points compared to
the prior year. Year-over-year flow-through for the Distribution Services segment was 10 percent,
consistent with our long-term expectations for the segment.
Outlook
The outlook for the Company in 2006 is positive, as high commodity prices are expected to keep
overall oil and gas activity high, and as our backlog for capital equipment sales has nearly
tripled since the beginning of 2005. A decline in commodity prices would have an adverse effect on
our operations. High levels of drilling across the North America land market and the Middle East,
in particular, are expected to continue to drive good results. Although the warm winter across
North America has led to seasonally high gas storage levels which have reduced spot gas prices, in
the longer term this region faces significant gas deliverability issues. North America has been
unable to meaningfully increase gas production despite significantly higher levels of gas drilling
over the past few years. Likewise, gas supply disruptions in Europe in recent months have exposed
that regions vulnerability to unstable gas supplies. Oil remains subject to significant political
risk in many regions as well, and the growth of China and other emerging economies has added
significant demand to the oil markets. We expect the high commodity prices that have resulted to
sustain very high levels of oilfield activity in 2006, provided the worlds major economies remain
strong.
Another important factor expected to contribute to our business over the long run is the nature of
mature and declining oil and gas fields. As production declines operators often increase drilling,
waterflooding, workover and well-stimulation activity to maintain production and cash flow. North
America is one of the most mature oil and gas production areas in the world, encompassing nearly
70% of all the rigs working around the world.
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We expect to increase our capital spending about 40 percent in 2006, to approximately $170 million,
primarily to add rental equipment in our Petroleum Services & Supplies segment. Additionally we
plan to add coiled tubing manufacturing capacity, and selectively invest in machining, assembly and
fabrication equipment to improve manufacturing efficiency in our Rig Technology group.
Varco Integration; Acquisitions
Upon the completion of the merger with Varco on March 11, 2005, we commenced our integration
activities to achieve merger synergies. The synergies result from, among other things, the
reduction of redundant overhead between the companies, and the combining of manufacturing, sales
and engineering functions in product lines where the two organizations overlap. Additionally, we
have brought in-house the manufacture of certain components that were previously purchased from
third party vendors. We continue to rationalize and consolidate products such as top drives, drill
pipe racking systems, iron roughnecks, and handling tools, into the most efficient factories, to
improve margins. Soon after the merger we announced our expectations of operating profit
improvements in the range of $60 million pre-tax on an annualized run rate basis, and that we
expected to achieve these results by the end of the first quarter of 2006. While there can be no
guarantee that this level will be achieved, we estimated that we achieved $13 million or
approximately $52 million annually during the fourth quarter, and expect to achieve our goal of
$60 million per year or $15 million per quarter within our originally announced timeframe
(excluding merger, transaction, integration, and stock-based compensation costs related to the
merger). We may report additional merger, transaction, integration and stock-based compensation
charges related to the merger during 2006.
We intend to continue to build and grow our business lines with corporate acquisitions and
strategic transactions, consistent with our past strategy. We have acquired businesses in the past
to supplement and broaden our offering of oilfield products, to improve our portfolio of
technologies, and to obtain operating efficiencies through consolidation of like businesses. We
have resumed our acquisition strategy in the second half of 2005 following the merger, and have
closed eight transactions since the merger.
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Results of Operations
Years Ended December 31, 2005 and December 31, 2004
The following table summarizes the Companys revenue and operating profit by operating segment in
2005 and 2004. The actual results include results from Varco operations from the acquisition date
of March 11, 2005 (in millions):
Years Ended December 31, | Variance | |||||||||||||||
2005 | 2004 | $ | % | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 2,216.8 | $ | 1,085.5 | $ | 1,131.3 | 104.2 | % | ||||||||
Petroleum Services & Supplies |
1,645.8 | 505.5 | 1,140.3 | 225.6 | % | |||||||||||
Distribution Services |
1,074.5 | 905.1 | 169.4 | 18.7 | % | |||||||||||
Eliminations |
(292.6 | ) | (178.0 | ) | (114.6 | ) | 64.4 | % | ||||||||
Total Revenue |
$ | 4,644.5 | $ | 2,318.1 | $ | 2,326.4 | 100.4 | % | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 247.7 | $ | 102.4 | $ | 145.3 | 141.9 | % | ||||||||
Petroleum Services & Supplies |
300.1 | 62.7 | 237.4 | 378.6 | % | |||||||||||
Distribution Services |
46.6 | 29.6 | 17.0 | 57.4 | % | |||||||||||
Unallocated expenses and eliminations |
(70.3 | ) | (18.7 | ) | (51.6 | ) | 275.9 | % | ||||||||
Integration costs and stock-based
compensation |
(47.3 | ) | | (47.3 | ) | | ||||||||||
Total Operating Profit |
$ | 476.8 | $ | 176.0 | $ | 300.8 | 170.9 | % | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
11.2 | % | 9.4 | % | ||||||||||||
Petroleum Services & Supplies |
18.2 | % | 12.4 | % | ||||||||||||
Distribution Services |
4.3 | % | 3.3 | % | ||||||||||||
Total Operating Profit % |
10.3 | % | 7.6 | % | ||||||||||||
Rig Technology
Rig Technology revenue for the year ended December 31, 2005 was $2,216.8 million, an increase of
$1,131.3 million (104.2%) compared to 2004. The 2005 Varco acquisition resulted in approximately
$767.3 million of additional revenue in 2005. The remainder of the increase can be attributed to
the growing market for capital equipment, as evidenced by backlog growth as well as increases in
spare parts and service revenue. The increase in orders and backlog can be attributed to increased
rig construction projects and higher capital investment by drilling contractors in 2005 as compared
to 2004.
Operating profit from Rig Technology was $247.7 million for the year ended December 31, 2005, an
increase of $145.3 million (141.9%) over the same period of 2004. The increase in operating profit
was primarily related to the acquisition of Varco, offset partially by a second quarter charge of
$21.7 million taken on a large Kazakhstan rig fabrication project as a result of additional costs
attributed to higher rig-up costs and more material than originally planned.
The Rig Technology group monitors its capital equipment backlog to plan its business. New orders
are added to backlog only when we receive a firm customer purchase order for major drilling rig
components or a signed contract related to a construction project. The capital equipment backlog
was $2.3 billion at December 31, 2005, an increase of $1.5 billion (191.6%) over backlog of $783
million (on a pro forma basis for the Varco acquisition) at December 31, 2004. Substantially all
of the current backlog will be delivered by the end of 2007.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies was $1,645.8 million for 2005 compared to $505.5 million
for 2004, an increase of $1,140.3 million (226%). The majority of the increase is attributable to
the addition of product lines acquired from Varco effective March 11, 2005, which totaled $984.8
million for the period. The remaining increase is attributable to high demand for downhole tools
and pumping products, which had revenue increases of 28% and 26%, respectively. These increases
were the
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result of strong North America and worldwide drilling markets, as reflected by rig count increases
of 18% and 15%, respectively, for 2005 compared to 2004. Petroleum Services & Supplies also
benefited from price increases implemented during 2005.
Operating profit from Petroleum Services & Supplies was $300.1 million for 2005 compared to $62.7
million for 2004, an increase of $237.4 million (379%). The majority of the increase was
attributable to the addition of product lines acquired from Varco effective March 11, 2005.
Operating profit from these product lines was $213.4 million for the period. The remaining
increase was attributable to higher profitability from downhole tool sales and rentals, and sales
of pumping products which had operating profit dollar increases of 103.6% and 31.3%, respectively.
Distribution Services
Revenue from Distribution Services totaled $1,074.5 million, an increase of $169.4 million (19%)
from the prior period. The number of drilling rigs actively searching for oil and gas is a key
metric for this business segment. According to the Baker Hughes rig count report, the average
number of rigs operating in the world in 2005 was up 14.7% over the prior period. The average
rig count in North America in 2005 was up 18.0% over the prior period to 1,839 rigs with our North
American revenues up $144.8 million (20%). In the International market, revenues increased 12%
while international rig count activity increased by 8.6%. From a product perspective,
maintenance, repair and operating supply (MRO) commodities in 2005 experienced a 16% increase
over 2004 and significant successive growth in all 4 quarters of 2005. Sales of our manufactured
products increased 29% with similar sales escalations during the year. Margins were essentially
flat for both MRO and original equipment manufacturer product groups largely due to a large portion
of these revenues locked in at committed margin rates to contractual customers. Tubular sales were
up 53% concentrated mainly in our Canadian operations.
Operating income increased $17.0 million in 2005 to $46.6 million or 4.3% of revenue. Improved
supplier rebates coupled with increased operating efficiencies largely achieved by absorbing the
revenue increase across an already established distribution infrastructure and expense base were
the main contributors to operating income improvement.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $70.3 million for the year ended December 31, 2005
compared to $18.7 million for 2004. The increase in operations costs was primarily due to costs
associated with Varco operations since the acquisition date and greater inter-segment profit
eliminations.
Stock-based compensation
Stock-based compensation expense of $15.6 million for 2005 was related to the amortization of
unvested options assumed as a result of the merger.
On February 21, 2006, the Company issued 2,344,000 stock options at an exercise price of $66.58.
The Company expects to recognize stock option expense of approximately $40 million in 2006.
Integration costs
Integration costs were $31.7 million for 2005 and consisted primarily of severance costs related to
former executive officers and employees of the Company.
Interest and financial costs
Interest and financial costs were $52.9 million for 2005 compared to $38.4 million for 2004. The
increase was primarily due to interest costs associated with debt assumed in the Varco transaction.
See summary of outstanding debt at December 31, 2005 under Liquidity and Capital Resources.
Provision for income taxes
The effective tax rate for the fiscal year-ended December 31, 2005 was 32.3% (32.3% excluding
integration costs and stock-based compensation associated with the Varco merger) compared to 15.6%
for 2004. The lower 2004 tax rate was due primarily to a non-recurring tax credit of $17 million
resulting from the release of a valuation allowance related to the American Jobs Creation Act of
2004. The tax rates reflect a lower percentage of earnings in foreign jurisdictions with lower tax
rates and reduced benefits in the US associated with export sales in 2005 compared to 2004. The US
laws granting this tax benefit were modified as part of the American Jobs Creation Act of 2004 and
this benefit will be phased out over the next year. A new tax benefit associated with US
manufacturing operations passed into law under the same Act will be phased in over the five years
beginning in 2005. Whereas the timing of the phase out of the export tax benefit and the phase in
of the manufacturing tax benefit may differ, we expect the tax reduction associated with the new
manufacturing deduction, when fully implemented, to be similar in amount to the export benefit. We
anticipate our tax rate for 2006 to be in the range of approximately 32% to 34% for continuing
operations.
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Years Ended December 31, 2004 and December 31, 2003
The following table summarizes the Companys revenue and operating profit by operating segment in
2004 and 2003 (in millions):
Years Ended December 31, | Variance | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 1,085.5 | $ | 880.1 | $ | 205.4 | 23.3 | % | ||||||||
Petroleum Services & Supplies |
505.5 | 446.3 | 59.2 | 13.3 | % | |||||||||||
Distribution Services |
905.1 | 792.0 | 113.1 | 14.3 | % | |||||||||||
Eliminations |
(178.0 | ) | (113.5 | ) | (64.5 | ) | 56.8 | % | ||||||||
Total Revenue |
$ | 2,318.1 | $ | 2,004.9 | $ | 313.2 | 15.6 | % | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 102.4 | $ | 96.8 | $ | 5.6 | 5.8 | % | ||||||||
Petroleum Services & Supplies |
62.7 | 73.7 | (11.0 | ) | (14.9 | %) | ||||||||||
Distribution Services |
29.6 | 6.5 | 23.1 | 355.4 | % | |||||||||||
Unallocated expenses and
eliminations |
(18.7 | ) | (12.9 | ) | (5.8 | ) | 45.0 | % | ||||||||
Total Operating Profit |
$ | 176.0 | $ | 164.1 | $ | 11.9 | 7.3 | % | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
9.4 | % | 11.0 | % | ||||||||||||
Petroleum Services & Supplies |
12.4 | % | 16.5 | % | ||||||||||||
Distribution Services |
3.3 | % | 0.8 | % | ||||||||||||
Total Operating Profit % |
7.6 | % | 8.2 | % | ||||||||||||
Operations
Revenues in 2004 were $313.2 million (15.6%) higher than the previous year, while operating profit
was up 7.3%. Yearly average oil and gas prices in 2004 were $41.37 and $5.95, an increase of 34%
and 8% over 2003. These higher oil and gas prices have encouraged many of our customers to order
new capital equipment, or refurbish their existing equipment, generating additional capital
equipment revenues in 2004 of $72 million. The number of worldwide rigs actively searching for oil
and gas increased approximately 10% in 2004 to a yearly average of 2,395 rigs. This metric is a key
driver of our noncapital equipment revenues which were $150 million higher in 2004. Drilling spare
parts, expendable pumps and related parts, downhole motors and fishing tools, service work, and
Distribution Services all showed significant increases during 2004. Despite the higher revenues and
operating profit, operating profit percent margins (down from 8.2% to 7.3%) were negatively
impacted by the increase of lower margin capital equipment revenues, higher steel prices during the
first half of the year and higher agent commissions. Operating expenses increased primarily due to
higher employee benefit costs.
One of our metrics used to plan the business is the capital equipment backlog. New orders are added
to backlog only when we receive a firm customer purchase order for major drilling rig components or
a signed contract related to a construction project. New orders received in 2004 for capital
equipment totaled $961 million, far exceeding the previous years record of $598 million. The
capital equipment backlog was $605 million at December 31, 2004, $339 million at December 31, 2003
and $364 million at December 31, 2002. All of the current backlog will be delivered by the end of
2006.
Unallocated Expenses and Eliminations
Unallocated expenses charges represent the unallocated portion of centralized and executive
management costs. Costs for 2004 totaled $18.7 million, an increase of $5.8 million from the prior
year. The majority of this increase is due to expenses incurred in conjunction with our efforts to
comply with the Sarbanes Oxley Act of 2002 and consulting fees incurred with various tax
initiatives.
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Interest and Financial Costs
Interest expense incurred in 2004 of $38.4 million was slightly below interest expense of $38.9
million incurred 2003. Our average borrowing cost for the year of 5.6 % was essentially the same as
2003.
Provision for Income Taxes
The Company is subject to U.S. federal, state and foreign taxes and recorded a combined tax rate of
15.6% in 2004 and 29.5% in 2003. The reduction in the 2004 effective tax rate was
primarily due to a non-recurring tax credit of $17 million resulting from the release of a
valuation allowance related to the American Jobs Creation Act of 2004.
The reduction in the 2003 effective tax rate was primarily due to the lower tax rate on increased
foreign income and the benefit associated with export sales.
Liquidity and Capital Resources
At December 31, 2005, the Company had cash and cash equivalents of $209.4 million, and total debt
of $841.3 million. At December 31, 2004, cash and cash equivalents were $142.7 million and total
debt was $500.0 million. The increase in cash holdings and outstanding debt was primarily a result
of cash acquired of $163.5 million and debt assumed of $492.8 million related to the Varco
acquisition. The Companys outstanding debt at December 31, 2005 consisted of $200.0 million of
5.65% senior notes due 2012, $200.0 million of 7.25% senior notes due 2011, $150.0 million of 6.5%
senior notes due 2011, $150.0 million of 5.5% senior notes due 2012, $100.0 million of 7.5% senior
notes due 2008, and other debt of $41.3 million. Included in other debt is the fair market value
adjustment of the Varco debt assumed in the acquisition, which resulted in additional debt
recognition of $29.2 million. The difference is being amortized to interest expense over the
remaining life of the debt.
Cash provided by operating activities in 2005 was $77.5 million compared to cash provided by
operating activities of $166.2 million in 2004. Cash was used by operations primarily through
increases in receivables of $293.9 million, inventories of $215.4 million, and costs in excess of
billings of $131.1 million. These negative cash flows were offset by net income of $286.9 million
plus non-cash charges of $114.6 million and $29.7 million of tax benefit from the exercise of
nonqualified stock options. Receivables and costs in excess of billings increased due to greater
revenue and activity in the fourth quarter of 2005 compared to the fourth quarter of 2004, while
inventory increased due to growing backlog orders.
For the fiscal year-ended 2005, cash provided by investing activities was $38.0 million compared
to $6.0 million used for 2004. Cash acquired in the Varco acquisition in the first quarter of 2005
was $163.5 million. Capital spending of $105.0 million was primarily related to rental assets
associated with the Companys Petroleum Services & Supplies operations and capital expansion
related to increased capacity for manufacturing operations.
For the fiscal year-ended 2005, cash used by financing activities was $40.4 million compared to
cash used of $95.3 million in 2004. Cash was used by financing activities through the repayment of
the Companys $150 million 6.875% senior notes offset partly by proceeds from exercised stock
options of $111.9 million.
The Companys $150 million 6.875% senior notes were repaid on July 1, 2005 using available cash
balances. On June 21, 2005, we amended and restated our existing $150 million revolving credit
facility with a syndicate of lenders to provide the Company a $500 million unsecured revolving
credit facility. The facility will expire in July 2010, and replaces the Companys $175 million
North American revolving credit facility and our Norwegian facility. The Company has the right to
increase the facility to $750 million and to extend the term of the facility for an additional
year. At December 31, 2005, there were no borrowings against this facility, and there were $123
million in outstanding letters of credit. Interest under this multicurrency facility is based upon
LIBOR, NIBOR or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.
We believe cash generated from operations and amounts available under the credit facilities and
from other sources of debt will be sufficient to fund operations, working capital needs, capital
expenditure requirements and financing obligations. We also believe increases in capital
expenditures caused by any need to increase manufacturing capacity can be funded from operations or
through debt financing.
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A summary of the Companys outstanding contractual obligations at December 31, 2005 is as follows
(in millions):
Payment Due by Period | ||||||||||||||||||||
Less than 1 | 2-3 | 4-5 | After 5 | |||||||||||||||||
Total | Year | Years | Years | Years | ||||||||||||||||
Total debt |
$ | 841.3 | $ | 5.7 | $ | 111.1 | $ | 2.7 | $ | 721.8 | ||||||||||
Operating leases |
198.8 | 52.8 | 65.5 | 35.2 | 45.3 | |||||||||||||||
Total contractual obligations |
$ | 1,040.1 | $ | 58.5 | $ | 176.6 | $ | 37.9 | $ | 767.1 | ||||||||||
Standby letters of credit |
$ | 262.2 | $ | 160.2 | $ | 76.8 | $ | 25.2 | $ | | ||||||||||
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. While not a
contractual obligation, the Company does expect to increase its capital spending approximately 40%
in 2006 to a range of $170 million, primarily for rental equipment for its Petroleum Services and
Supplies segment. We expect to fund future cash acquisitions and capital spending primarily with
cash flow from operations and borrowings, including the unborrowed portion of the 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.
Inflation has had an impact on certain of our operations in recent years. We believe that the
higher costs for energy, steel and other commodities experienced in 2005 have largely been
mitigated by increased prices and component surcharges for the products we sell. However, higher
steel, labor, energy or other commodity prices may adversely impact future periods.
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 related to allowance for
doubtful accounts; inventory reserves; warranty accruals; impairments of long-lived assets
(including goodwill); income taxes and pensions and other postretirement benefits. Our estimates
are based on historical experience and on our future expectations that we believe are reasonable;
the combination of these factors forms the basis for making judgments about the carrying values of
assets and liabilities that are not readily apparent from other sources. Actual results are likely
to differ from our current estimates and those differences may be material.
Revenue Recognition
The Companys products and services are sold based upon purchase orders or contracts with the
customer that include fixed or determinable prices and that do not include right of return or other
similar provisions or other significant post delivery obligations. Except for certain construction
contracts 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, collectibility 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 costs 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 that are built or constructed to the customers specifications, and are manufactured
outside the Companys normal manufacturing process and marketed outside of the Companys normal
marketing channels. Projects recognized under the percentage-of-completion method include the
following characteristics: 1) the contracts include custom designs for customer specific
applications; 2) components are often modified with change orders throughout the project; 3) the
structural design is unique and requires significant engineering efforts; and 4) construction
projects often have progress payments. This method requires us to make estimates regarding the
total costs of the project, our progress against the project schedule and the estimated completion
date, all of which impact the amount of revenue and gross margin we recognize in each reporting
period. Changes in job performance, job conditions, and estimated profitability, including those
arising from contract penalty provisions, and final contract settlements may result in revisions to
costs and income and are recognized in the period in which the revisions are determined. Profit
incentives are included in revenues when their realization is reasonably assured. Provisions for
anticipated losses on uncompleted contracts are recorded in full when such losses become evident.
The Company measures the extent of progress towards completion on these projects using either input
or output based methods that are appropriate to the contract circumstances. The
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output methods are based upon engineering estimates and the input measures are based upon the ratio
of costs incurred to the total projected costs.
Allowance for Doubtful Accounts
Allowance for doubtful accounts are determined on a specific identification basis when we believe
that the required payment of specific amounts owed to us is not probable. A substantial portion of
the Companys revenues come from international oil companies, 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, our customers may be unable
to repay these receivables, and additional allowances could be required.
Inventory Reserves
Reserves for inventory are determined based on our historical usage of inventory on-hand as well as
our future expectations related to requirements to provide spare parts for our substantial
installed base and new products. Changes in worldwide oil and gas drilling activity and the
development of new technologies associated with the drilling industry could require the Company to
record additional allowances to reduce the value of inventory to the lower of its cost or net
realizable value.
Business Acquisitions
Business acquisitions are accounted for using the purchase method of accounting. The cost of the
acquired company is allocated to identifiable tangible and intangible assets based on estimated
fair value, with the excess allocated to goodwill.
Impairment of Long-Lived Assets (Including Goodwill)
Long-lived assets, which include property and equipment, goodwill, and identified intangible
assets, comprise a significant amount of the Companys 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 useful lives. Additionally, the carrying
values of these assets are reviewed for impairment periodically or 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. 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 Companys
products and services, future market conditions and technological developments. Significant and
unanticipated changes to these assumptions or the intended use of these assets could require a
provision for impairment in a future period.
In accordance with SFAS 142, the Company performs a review of goodwill for impairment annually or
earlier if indicators of potential impairment exist. The annual impairment tests are performed
during the fourth quarter of each year. If it is determined that goodwill is impaired, that
impairment is measured based on the amount by which the book value of goodwill exceeds its implied
fair value. The implied fair value of goodwill and identified intangibles is determined by
deducting the fair value of a reporting units identifiable assets and liabilities from the fair
value of that reporting unit as a whole. Additional impairment assessments may be performed on an
interim basis if the Company encounters events or changes in circumstances that would indicate
that, more likely than not, the carrying amount of goodwill and identified intangibles has been
impaired. Fair value of the reporting units is determined based on internal management estimates,
using a combination of three methods: discounted cash flow, comparable companies, and
representative transactions.
Income Taxes
In accordance with the provisions of SFAS No. 109, Accounting for Income Taxes, we account for
income taxes using the asset and liability method. In determining income (loss) for financial
statement purposes, we must make certain estimates and judgments. These estimates and judgments
affect the calculation of certain tax liabilities and the determination of the recoverability of
certain of the deferred tax assets, which arise from temporary differences between the tax and
financial statement recognition of revenue and expense. Deferred tax assets are also reduced by a
valuation allowance if, based on the weight of available evidence, it is more likely than not that
some portion or all of the recorded deferred tax assets will not be realized in future periods. In
evaluating our ability to recover our deferred tax assets we consider all available positive and
negative evidence including our past operating results, the existence of cumulative losses in the
most recent years and our forecast of future taxable income. In estimating future taxable income,
we develop assumptions including the amount of future state, federal and international pretax
operating income, reversal of temporary differences and the implementation of feasible and prudent
tax planning strategies. These assumptions require significant judgment about the forecasts of
future taxable income and are consistent with the plans and estimates we are using to manage the
underlying businesses.
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We currently have recorded valuation allowances that we intend to maintain until it is more likely
than not the deferred tax assets will be realized. Other than valuation allowances associated with
tax attributes acquired through acquisitions, our income tax expense recorded in the future will be
reduced to the extent of decreases in our valuation allowances. The realization of our 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 we
record an additional valuation allowance against our 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 our future earnings. If a change in a valuation allowance occurs, which was
established in connection with an acquisition, such adjustment may impact goodwill rather than the
income tax provision. In addition, the calculation of our tax liabilities involves dealing with
uncertainties in the application of complex tax regulations in a multitude of jurisdictions across
our global operations. We recognize potential liabilities and record tax reserves for anticipated
tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the
extent to which, additional taxes will be due. These tax liabilities are reflected net of related
tax loss carry forwards. We adjust these reserves in light of changing facts and circumstances;
however, due to the complexity of some of these uncertainties, the ultimate resolution may result
in a payment that is materially different from our current estimate of the tax liabilities. If our
estimate of tax liabilities proves to be less than the ultimate assessment, an additional charge to
expense would result. If payment of these amounts ultimately proves to be less than the recorded
amounts, the reversal of the liabilities would result in tax benefits being recognized in the
period when we determine the reserves are no longer necessary. If the tax liabilities relate to tax
uncertainties existing at the date of the acquisition of a business, the adjustment of such tax
liabilities will result in an adjustment to the goodwill recorded at the date of acquisition.
Pensions and Other Postretirement Benefits
The Company accounts for our defined benefit pension plans in accordance with Statement of
Financial Accounting Standards No. 87, Employers Accounting for Pensions (FAS 87), which requires
that amounts recognized in the financial statements be determined on an actuarial basis.
Significant elements in determining our pension income or expense in accordance with FAS 87 are the
discount rate assumption and the expected return on plan assets. The discount rate used
approximates the weighted average rate of return on high-quality fixed income investments whose
maturities match the expected payouts. The expected return on plan assets is based upon the
geometric mean of historical returns of a number of different equities, including stocks, bonds and
U.S. treasury bills. The assumed long-term rate of return on assets is applied to a calculated
value of plan assets which results in an estimated return on plan assets that is included in
current year pension income or expense. The difference between this expected return and the actual
return on plan assets is deferred and amortized against future pension income or expense.
Recently Issued Accounting Standards
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, Inventory
Costs an amendment of ARB 43, Chapter 4 (SFAS 151). SFAS 151 clarifies the accounting for
abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph
5 of Accounting Research Bulletin (ARB) 43, Chapter 4 Inventory Pricing, previously stated
that under certain circumstances, items such as idle facility expense, excessive spoilage, double
freight, and rehandling costs may be so abnormal as to require treatment as current-period
charges. SFAS 151 requires that those items be recognized as current-period charges regardless of
whether they meet the criterion of so abnormal. In addition, SFAS 151 requires that the
allocation of fixed production overheads to the costs of conversion be based on the normal capacity
of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15,
2005. We do not believe the implementation of SFAS 151 will have a material impact on our
financial position, results of operations or cash flows.
In March 2005, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB)
No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123(R) and
certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of
share-based payment arrangements for public companies, including assumptions such as expected
volatility and expected term. We are assessing the impact SFAS No. 123(R) and SAB No. 107 will have
on our consolidated financial statements and which transition methods allowed by SFAS No. 123(R)
will be elected. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No.
123(R) for public companies. As a result, SFAS No. 123(R) will be effective for us on January 1,
2006.
In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations, (FIN 47) which clarifies when an
entity is required to recognize a liability for the fair value of a conditional asset retirement
obligation. FIN 47 will be effective for fiscal years ending after December 15, 2005, with earlier
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adoption encouraged. We are currently evaluating the impact this interpretation may have on our
financial position, results of operations or cash flows.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, Accounting
Changes and Error Corrections (SFAS 154), which replaces APB Opinion No. 20, Accounting
Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154
requires a voluntary change in accounting principle to be applied retrospectively to all prior
period financial statements so that those financial statements are presented as if the current
accounting principle had always been applied. SFAS 154 is effective for accounting changes and
correction of errors made after January 1, 2006, with early adoption permitted. We do not expect
the adoption of SFAS 154 to have a material impact on our financial position, results of operations
or cash flows.
The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 123R, Share-Based Payment (SFAS 123R), which originally required implementation for
interim or annual reporting periods beginning after June 15, 2005. However, in April 2005, the SEC
adopted a new rule to amend the compliance date to the beginning of the Companys next fiscal year,
January 1, 2006. SFAS 123R requires us to recognize the cost of employee services received in
exchange for the companys equity instruments. Currently, in accordance with APB Opinion 25, we
record the intrinsic value of stock based compensation as expense. Accordingly, no compensation
expense is currently recognized for fixed stock option plans, except as described in Notes 2 and 3
related to the Varco Merger, as the exercise price equals the stock price on the date of grant.
Under SFAS 123R, we will be required to measure compensation expense over the options vesting
period based on the stock options fair value at the date the options are granted and classify the
tax benefit from the exercise of nonqualified stock options as a financing activity in the
statement of cash flow. SFAS 123R allows for the use of the Black-Scholes or a lattice
option-pricing model to value such options. We will use the Black-Scholes option-pricing model to
calculate the fair value of the options. We have elected to adopt SFAS 123R on a modified
prospective basis. Note 2 illustrates the effects on net income and earnings per share if we had
adopted SFAS 123R using the Black-Scholes option-pricing model.
ForwardLooking 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. 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.
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Supplemental Pro Forma Comparison
The pro forma information reflects results as if the Varco acquisition occurred at the beginning of
the first quarter of 2005 and 2004. The results prior to the merger date include the estimated
effect of purchase accounting adjustments, but do not include any effect from cost savings that may
result from the merger and do not include restructuring charges, amortization of unvested
compensation expense associated with options issued as part of the Merger, litigation gains and
transaction-related costs in prior periods. The unaudited pro forma financial statements are
presented for informational purposes only and are not necessarily indicative of actual results of
operations or financial position that would have occurred had the transaction been consummated at
the beginning of the period presented, nor are they necessarily indicative of future results.
Pro forma combined operating results by segment are as follows (in millions):
Years Ended December 31, | Variance | |||||||||||||||
2005 | 2004 | $ | % | |||||||||||||
Revenue: |
||||||||||||||||
Rig Technology |
$ | 2,335.7 | $ | 1,727.6 | $ | 608.1 | 35.2 | % | ||||||||
Petroleum Services & Supplies |
1,838.7 | 1,431.5 | 407.2 | 28.4 | % | |||||||||||
Distribution Services |
1,074.5 | 905.1 | 169.4 | 18.7 | % | |||||||||||
Eliminations |
(296.5 | ) | (178.0 | ) | (118.5 | ) | 66.6 | % | ||||||||
Total Revenue |
$ | 4,952.4 | $ | 3,886.2 | $ | 1,066.2 | 27.4 | % | ||||||||
Operating Profit: |
||||||||||||||||
Rig Technology |
$ | 264.1 | $ | 180.7 | $ | 83.4 | 46.2 | % | ||||||||
Petroleum Services & Supplies |
328.6 | 218.5 | 110.1 | 50.4 | % | |||||||||||
Distribution Services |
46.6 | 29.6 | 17.0 | 57.4 | % | |||||||||||
Unallocated expenses and
eliminations |
(81.5 | ) | (57.7 | ) | (23.8 | ) | 41.2 | % | ||||||||
Total Operating Profit |
$ | 557.8 | $ | 371.1 | $ | 186.7 | 50.3 | % | ||||||||
Operating Profit %: |
||||||||||||||||
Rig Technology |
11.3 | % | 10.5 | % | ||||||||||||
Petroleum Services & Supplies |
17.9 | % | 15.3 | % | ||||||||||||
Distribution Services |
4.3 | % | 3.3 | % | ||||||||||||
Total Operating Profit % |
11.3 | % | 9.5 | % | ||||||||||||
Rig Technology
Rig Technology revenue for the year ended December 31, 2005 was $2.3 billion, an increase of $608.1
million (35.2%) compared to 2004. The increase can be attributed to the growing market for capital
equipment, as evidenced by backlog growth, as well as increases in spare parts and service revenue.
The increase in orders and backlog can be attributed to increased rig construction projects and
higher capital investment by drilling contractors in 2005 as compared to 2004. Operating profit
from Rig Technology was $264.1 million for the for the year ended December 31, 2005, an increase of
$83.4 million (46.2%) over 2004, primarily as result of the increase in business activity discussed
above, partially offset by the second quarter charge of $21.7 million taken on a large Kazakhstan
rig fabrication project as a result of additional costs attributed to higher rig-up costs and more
material than originally planned. Additionally, the group was adversely affected by inventory,
legal, allowance for doubtful accounts charges, and charges on a crane order, which totaled $10.5
million in 2005.
Petroleum Services & Supplies
Revenue on a pro forma basis from Petroleum Services & Supplies was $1,838.7 million for 2005
compared to $1,431.5 million for 2004, an increase of $407.2 million (28.4%). The increase is
attributable to a significant increase in North America and worldwide drilling activity, price
increases implemented during 2005, strong spare parts and consumable sales to support increased
drilling and acquisitions made in 2004 and 2005. The revenue increase attributable to acquisitions
is approximately $17.6 million. Operating profit on a pro forma basis for Petroleum Services &
Supplies was $328.6 million for 2005 compared to
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$218.5 million for 2004, an increase of $110.1 million (50.4%). Improved results were posted
across all product line with the exception of pipeline inspection.
Distribution Services
Results for Distribution Services on a pro forma basis are the same as they are for actual. See
discussion above regarding Distribution Services.
Unallocated expenses and eliminations
Unallocated expenses and eliminations on a pro forma basis were $81.5 million for 2005 compared to
$57.7 million for 2004. The increase in unallocated operating costs was due to greater
inter-segment profit eliminations, cost increases associated with complying with Sarbanes-Oxley
legislation, and greater legal costs, offset by corporate overhead consolidation savings. The 2004
unallocated expenses and eliminations amounts benefited from several miscellaneous credits,
including litigation recoveries, insurance recoveries, the expiration of an excise tax accrual, and
other items which did not recur in 2005.
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 operations in foreign countries, including Canada, Norway and the United Kingdom, as well
as operations in Latin America, China and other European 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 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 do impact income. During the
years ended December 31, 2005, 2004, and 2003, the Company reported foreign currency gains (losses)
of $2.9 million, ($9.3) million, and ($7.2) million respectively. The gains (losses) were primarily
due to exchange rate fluctuations related to monetary asset balances denominated in currencies
other than the functional currency. We do not believe that a hypothetical 10% movement in these
foreign currencies would have a material impact on our earnings due to the element of natural
hedges that would impact both revenue and expenses.
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. 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.
At December 31, 2005, we had also entered into foreign currency forward contracts with notional
amounts aggregating $380.9 million to hedge exposure to currency fluctuations in various foreign
currencies, including the British Pound Sterling, the Euro, Norwegian Kroner and the Singapore
Dollar. These exposures arise when local currency operating expenses are not in balance with local
currency revenue collections. These foreign currency forward contracts are designated as cash flow
hedging instruments and are fully effective. Based on quoted market prices as of December 31, 2005
and 2004 for contracts with similar terms and maturity dates, we have recorded a gain (loss) of
($7.3) million and $1.2 million respectively to adjust these foreign currency forward contracts to
their fair market value. This gain (loss) is included in other comprehensive income in the
consolidated balance sheet. It is expected that $6.6 million of the loss will be reclassified into
earnings within the next 12 months. The Company currently has cash flow hedges in place through the
first quarter of 2008. We do not believe that a hypothetical 10% movement in these foreign
currencies would have a material impact on our earnings related to these forward contracts.
The company also had several foreign currency forward contracts with notional amounts aggregating
$223.1 million designated and qualifying as fair value hedges to hedge exposure to the Euro,
Norwegian Kroner, and Singapore Dollar. Based on quoted market prices as of December 31, 2005 and
2004 for contracts with similar terms and maturity dates, we recorded a loss of $5.1 million and
$1.9 million respectively to adjust these foreign currency forward contracts to their fair market
value. This loss offsets designated gains on firm commitments. We do not believe that a
hypothetical 10% movement in these foreign currencies would have a material impact on our earnings
related to these forward contracts.
The Company has other financial market risk sensitive instruments denominated in foreign currencies
totaling $19.7 million as of December 31, 2005 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
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applicable foreign currency exchange rates on these financial market risk sensitive instruments
would affect net income by $1.3 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
unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our
exposure is limited to the foreign currency rate differential.
Interest Rate Risk
At December 31, 2005 our long term borrowings consisted of $100 million in 7.5% senior notes, $150
million in 6.5% senior notes, $200 million in 7.25% senior notes, $200 million in 5.65% senior
notes and $150 million in 5.5% senior notes. We had $41.3 million of borrowings under our other
credit facilities at December 31, 2005. We occasionally have borrowings under our other credit
facilities, 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 facilities, we may, at our option, fix the interest rate for
certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to 6 months. Our
objective is to maintain a portion of our debt in variable rate borrowings for the flexibility
obtained regarding early repayment without penalties and lower overall cost as compared with
fixed-rate borrowings.
As of December 31, 2005, we had three interest rate swap agreements with an aggregate notional
amount of $100 million associated with our 2008 senior notes. Under this agreement, we receive
interest at a fixed rate of 7.5% and pay interest at a floating rate of six-month LIBOR plus a
weighted average spread of approximately 4.675%. The swap agreements will settle semi-annually and
will terminate in February 2008. The swap agreements originally entered into by Varco were
recorded at their fair market value at the date of the Merger and no longer qualify as effective
hedges under FAS 133. The swaps will be marked-to-market for periods subsequent to the Merger and
any change in their value will be reported as an adjustment to interest expense. The change in the
fair market value of the interest swap agreements resulted in a $0.3 million increase in interest
expense for the period ended December 31, 2005.
ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTARY DATA
Attached hereto and a part of this report are financial statements and supplementary data listed in
Item 15.
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
Our Chief Executive Officer and Chief Financial Officer, based on their evaluation of our
disclosure controls and procedures (as defined in Exchange Act
Rule 13a-14(c)) as of December 31, 2005, have concluded that our disclosure
controls and procedures were effective as of December 31, 2005
to provide reasonable assurance that the information required to be disclosed by
us in the reports we file or submit under the Securities Exchange Act of 1934, as amended (the
Exchange Act) is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commissions rules and forms.
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
certificates are included herein as Exhibits 31.1 and 31.2.
(ii) Internal
Control Over Financial Reporting
(a) Managements
annual report on internal control over financial reporting.
The
Companys management report on internal control over financial
reporting is set forth in this annual report on Page 48 and is
incorporated herein by reference.
(b) Attestation
report of the registered public accounting firm
The
attestation report of Ernst & Young LLP, the Companys
independent registered public accounting firm, on managements
assessment of the effectiveness of the Companys internal
control over financial reporting is set forth in this
annual report on Page 49 and is incorporated by reference herein.
(c) Changes in internal control
There were no changes in the Companys internal control over financial reporting that
occurred during the Companys last fiscal quarter covered by this report that have materially
affected, or are reasonably likely to materially affect, the Companys internal control over
financial reporting, except for the following:
During 2005 the Company implemented the following steps, among others, to remediate and
strengthen its internal controls over materials-in-transit inventory and intercompany account
reconciliations:
1. | The Company has changed its reconciliation process to require individual subsidiaries to reconcile all intercompany balances with counterparties on a monthly and transaction-by-transaction basis in a timely manner; | |
2. | The Company appointed a worldwide intercompany controller to monitor the effectiveness of intercompany controls; and | |
3. | The Company has corrected errors and improved processes to develop detailed support for its outstanding materials-in-transit account balances. |
As a result of these improvements, management of the Company believes that its internal controls
relating to the materials-in-transit and intercompany accounts are functioning effectively.
ITEM
9B. OTHER INFORMATION
None.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Incorporated by reference to the definitive Proxy Statement for the 2006 Annual Meeting of
Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the definitive Proxy Statement for the 2006 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 2006 Annual Meeting of
Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated by reference to the definitive Proxy Statement for the 2006 Annual Meeting of
Stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2006 Annual Meeting of
Stockholders.
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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 |
50 | |||
Consolidated Statement of Income |
51 | |||
Consolidated Statements of Cash Flows |
52 | |||
Consolidated Statements of Stockholders Equity and Comprehensive Income |
53 | |||
Notes to Consolidated Financial Statements |
54 |
(2) | Financial Statement Schedule |
Schedule II Valuation and Qualifying Accounts |
74 |
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, between National-Oilwell, Inc. and Varco International, Inc. (4). | |
3.1
|
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1). | |
3.2
|
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.2) (7). | |
10.1
|
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2). | |
10.2
|
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreements with Kevin A. Neveu and Mark A. Reese. (Exhibit 10.2) (2). | |
10.3
|
Form of Amended and Restated Executive Agreement of Clay C. Williams and Haynes Smith. (Exhibit 10.12) (3). | |
10.4
|
National Oilwell Varco Long-Term Incentive Plan (5)*. | |
10.5
|
Form of Employee Stock Option Agreement (Exhibit 10.1) (8) | |
10.6
|
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (8). | |
10.7
|
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6). | |
21.1
|
Subsidiaries of the Registrant | |
23.1
|
Consent of Ernst & Young LLP | |
24.1
|
Power of Attorney (included on signature hereto). |
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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. |
* | Compensatory plan or arrangement for management or others | |
(1) | Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000. | |
(2) | Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002. | |
(3) | Filed as an Exhibit to Varco International, Inc.s Quarterly Report on Form 10-Q filed on May 6, 2004. | |
(4) | Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004. | |
(5) | Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005. | |
(6) | Filed as an Exhibit to our Current Report on Form 8-K filed on June 23, 2005. | |
(7) | Filed as an Exhibit to our Current Report on Form 8-K filed on November 18, 2005. | |
(8) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006. |
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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: March 2, 2006 | By: | /s/ MERRILL A. MILLER, JR. | ||
Merrill A. Miller, Jr. | ||||
Chairman, President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.
Each person whose signature appears below in so signing, constitutes and appoints Merrill A.
Miller, Jr. and Clay C. Williams, and each of them acting alone, his true and lawful
attorney-in-fact and agent, with full power of substitution, for him and in his name, place and
stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange
Commission any and all amendments to this report, and in each case to file the same, with all
exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all
that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue
hereof.
Signature | Title | Date | ||
/s/ MERRILL A. MILLER, JR.
|
Chairman, President and Chief Executive Officer | March 2, 2006 | ||
/s/ CLAY C. WILLIAMS
|
Senior Vice President and Chief Financial Officer | March 2, 2006 | ||
/s/ ROBERT W. BLANCHARD
|
Vice President, Corporate Controller and Chief Accounting Officer | March 2, 2006 | ||
/s/ GREG L. ARMSTRONG
|
Director | March 2, 2006 | ||
/s/ ROBERT E. BEAUCHAMP
|
Director | March 2, 2006 | ||
/s/ BEN A. GUILL
|
Director | March 2, 2006 | ||
/s/ DAVID D. HARRISON
|
Director | March 2, 2006 | ||
/s/ ROGER L. JARVIS
|
Director | March 2, 2006 | ||
/s/ ERIC L. MATTSON
|
Director | March 2, 2006 | ||
/s/ JEFFERY A. SMISEK
|
Director | March 2, 2006 | ||
/s/ JAMES D. WOODS
|
Director | March 2, 2006 |
46
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
National Oilwell Varco, Inc.
National Oilwell Varco, Inc.
We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of
December 31, 2005 and 2004 and the related consolidated statements of income, stockholders equity
and comprehensive income, and cash flows for each of the three years in the period ended December
31, 2005. Our audits also included the financial statement schedule listed in the index at Item
15(a). These financial statements and schedule are the responsibility of the Companys management.
Our responsibility is to express an opinion on these financial statements and schedule based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of National Oilwell Varco, Inc. at December
31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of
the three years in the period ended December 31, 2005, 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 have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of National Oilwell Varco, Inc.s internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 2, 2006 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 2, 2006
March 2, 2006
47
Table of Contents
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
National Oilwell Varco, Inc.s management is responsible for establishing and maintaining adequate
internal control over financial reporting. National Oilwell Varco, Inc.s internal control system
was designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial
reporting objectives because of its inherent limitations. Internal control over financial reporting
is a process that involves human diligence and compliance and is subject to lapses in judgment and
breakdowns resulting from human failures. Internal control over financial reporting also can be
circumvented by collusion or improper management override. Because of such limitations, there is a
risk that material misstatements may not be prevented or detected on a timely basis by internal
control over financial reporting. However, these inherent limitations are known features of the
financial reporting process. Therefore, it is possible to design into the process safeguards to
reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled Internal ControlIntegrated
Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway
Commission to evaluate the effectiveness of the Companys internal control over financial
reporting. Management has concluded that the Companys internal control over financial reporting
was effective as of December 31, 2005. Ernst & Young LLP has issued an attestation report on
managements assessment of the Companys internal control over financial reporting.
/s/ Merrill A. Miller, Jr
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
/s/ Clay C. Williams
Clay C. Williams
Senior Vice President and
Chief Financial Officer
Clay C. Williams
Senior Vice President and
Chief Financial Officer
Houston, Texas
March 2, 2006
March 2, 2006
48
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Shareholders
National Oilwell Varco, Inc.
National Oilwell Varco, Inc.
We have audited managements assessment, included in the accompanying Managements Report on
Internal Control over Financial Reporting, that National Oilwell Varco, Inc. maintained effective
internal control over financial reporting as of December 31, 2005, based on criteria established in
Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (the COSO criteria). National Oilwell Varco, Inc.s management is responsible
for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility is to express an
opinion on managements assessment and an opinion on the effectiveness of the Companys 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, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, 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 companys 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
companys 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 companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that National Oilwell Varco, Inc. maintained effective
internal control over financial reporting as of December 31, 2005, is fairly stated, in all
material respects, based on the COSO criteria. Also, in our opinion, National Oilwell Varco, Inc.
maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2005, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of National Oilwell Varco, Inc. as of
December 31, 2005 and 2004, and the related consolidated statements of income, stockholders equity
and comprehensive income, and cash flows for each of the three years in the period ended December
31, 2005 of National Oilwell Varco, Inc. and our report dated March 2, 2006 expressed an
unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 2, 2006
March 2, 2006
49
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
December 31, | ||||||||
2005 | 2004 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 209.4 | $ | 142.7 | ||||
Receivables, net |
1,139.2 | 480.1 | ||||||
Inventories, net |
1,198.3 | 635.3 | ||||||
Costs in excess of billings |
341.9 | 226.5 | ||||||
Deferred income taxes |
58.6 | 15.6 | ||||||
Prepaid and other current assets |
50.8 | 15.0 | ||||||
Total current assets |
2,998.2 | 1,515.2 | ||||||
Property, plant and equipment, net |
877.6 | 255.1 | ||||||
Deferred income taxes |
52.2 | 55.1 | ||||||
Goodwill |
2,117.7 | 639.0 | ||||||
Intangibles, net |
611.5 | 91.0 | ||||||
Other assets |
21.3 | 21.1 | ||||||
$ | 6,678.5 | $ | 2,576.5 | |||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 568.2 | $ | 407.7 | ||||
Accrued liabilities |
530.1 | 209.5 | ||||||
Current portion of long-term debt and short-term borrowings |
5.7 | 150.0 | ||||||
Accrued income taxes |
83.2 | 37.0 | ||||||
Total current liabilities |
1,187.2 | 804.2 | ||||||
Long-term debt |
835.6 | 350.0 | ||||||
Deferred income taxes |
373.3 | 102.8 | ||||||
Other liabilities |
63.7 | 31.5 | ||||||
Total liabilities |
2,459.8 | 1,288.5 | ||||||
Commitments and contingencies |
||||||||
Minority interest |
24.5 | 17.8 | ||||||
Stockholders equity: |
||||||||
Common stock par value $.01; 174,362,488 and 85,995,266 shares
issued and outstanding at December 31, 2005 and December 31, 2004 |
1.7 | 0.9 | ||||||
Additional paid-in capital |
3,400.9 | 692.9 | ||||||
Unearned stock-based compensation |
(16.5 | ) | | |||||
Accumulated other comprehensive income (loss) |
(21.8 | ) | 33.4 | |||||
Retained earnings |
829.9 | 543.0 | ||||||
4,194.2 | 1,270.2 | |||||||
$ | 6,678.5 | $ | 2,576.5 | |||||
The accompanying notes are an integral part of these statements.
50
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Revenue: |
||||||||||||
Sales |
$ | 3,605.5 | $ | 2,137.8 | $ | 1,863.2 | ||||||
Services |
1,039.0 | 180.3 | 141.7 | |||||||||
Total |
4,644.5 | 2,318.1 | 2,004.9 | |||||||||
Cost of revenue: |
||||||||||||
Cost of sales |
2,905.1 | 1,700.6 | 1,451.2 | |||||||||
Cost of services |
752.2 | 113.7 | 84.4 | |||||||||
Total |
3,657.3 | 1,814.3 | 1,535.6 | |||||||||
Gross profit |
987.2 | 503.8 | 469.3 | |||||||||
Selling, general, and administrative |
463.1 | 327.8 | 305.2 | |||||||||
Stock-based compensation |
15.6 | | | |||||||||
Integration costs |
31.7 | | | |||||||||
Operating income |
476.8 | 176.0 | 164.1 | |||||||||
Interest and financial costs |
(52.9 | ) | (38.4 | ) | (38.9 | ) | ||||||
Interest income |
4.9 | 3.5 | 2.3 | |||||||||
Other income (expense), net |
1.2 | (2.2 | ) | (5.7 | ) | |||||||
Income before income taxes and minority interest |
430.0 | 138.9 | 121.8 | |||||||||
Provision for income taxes |
138.9 | 21.6 | 35.9 | |||||||||
Income before minority interest |
291.1 | 117.3 | 85.9 | |||||||||
Minority interest in income of consolidated
subsidiaries |
4.2 | 2.1 | 6.2 | |||||||||
Net income |
$ | 286.9 | $ | 115.2 | $ | 79.7 | ||||||
Net income per share: |
||||||||||||
Basic |
$ | 1.83 | $ | 1.34 | $ | 0.94 | ||||||
Diluted |
$ | 1.81 | $ | 1.33 | $ | 0.94 | ||||||
Weighted average shares outstanding: |
||||||||||||
Basic |
156.4 | 85.8 | 84.5 | |||||||||
Diluted |
158.3 | 86.5 | 85.0 | |||||||||
The accompanying notes are an integral part of these statements.
51
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Cash flow from operating activities: |
||||||||||||
Net income |
$ | 286.9 | $ | 115.2 | $ | 79.7 | ||||||
Adjustments to reconcile net income to net cash provided
by operating activities: |
||||||||||||
Depreciation and amortization |
114.6 | 44.0 | 39.2 | |||||||||
Tax benefit from exercise of nonqualified stock options |
29.7 | 3.4 | 3.9 | |||||||||
Other |
18.7 | (11.8 | ) | 14.0 | ||||||||
Changes in assets and liabilities, net of acquisitions: |
||||||||||||
Receivables |
(293.9 | ) | (8.6 | ) | (6.2 | ) | ||||||
Inventories |
(215.4 | ) | (105.8 | ) | (56.4 | ) | ||||||
Costs in excess of billings |
(131.1 | ) | (106.4 | ) | (53.8 | ) | ||||||
Prepaid and other current assets |
(8.6 | ) | 27.4 | (13.9 | ) | |||||||
Accounts payable |
68.1 | 174.3 | 53.4 | |||||||||
Billings in excess of costs |
94.5 | (17.7 | ) | (12.5 | ) | |||||||
Other assets/liabilities, net |
114.0 | 52.2 | (16.4 | ) | ||||||||
Net cash provided by operating activities |
77.5 | 166.2 | 31.0 | |||||||||
Cash flow from investing activities: |
||||||||||||
Purchases of property, plant and equipment |
(105.0 | ) | (39.0 | ) | (32.4 | ) | ||||||
Cash acquired in Varco merger |
163.5 | | | |||||||||
Other |
(20.5 | ) | 33.0 | (70.1 | ) | |||||||
Net cash provided (used) by investing activities |
38.0 | (6.0 | ) | (102.5 | ) | |||||||
Cash flow from financing activities: |
||||||||||||
Borrowing against lines of credit |
418.8 | 521.6 | 454.6 | |||||||||
Payments against lines of credit and other debt |
(571.1 | ) | (631.5 | ) | (439.1 | ) | ||||||
Proceeds from stock options exercised |
111.9 | 14.6 | 9.7 | |||||||||
Net cash provided (used) by financing activities |
(40.4 | ) | (95.3 | ) | 25.2 | |||||||
Effect of exchange rate changes on cash |
(8.4 | ) | 3.6 | 2.2 | ||||||||
Net increase (decrease) in cash and cash equivalents |
66.7 | 68.5 | (44.1 | ) | ||||||||
Cash and cash equivalents, beginning of period |
142.7 | 74.2 | 118.3 | |||||||||
Cash and cash equivalents, end of period |
$ | 209.4 | $ | 142.7 | $ | 74.2 | ||||||
Supplemental disclosures of cash flow information: |
||||||||||||
Cash payments during the period for: |
||||||||||||
Interest |
$ | 61.5 | $ | 34.0 | $ | 35.1 | ||||||
Income taxes |
$ | 88.3 | $ | 21.4 | $ | 30.7 |
The accompanying notes are an integral part of these statements.
52
Table of Contents
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY AND COMPREHENSIVE INCOME
(In millions)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY AND COMPREHENSIVE INCOME
(In millions)
Accumulated | ||||||||||||||||||||||||||||
Additional | Unearned | Other | ||||||||||||||||||||||||||
Shares | Common | Paid in | Stock-Based | Comprehensive | Retained | |||||||||||||||||||||||
Outstanding | Stock | Capital | Compensation | Income (Loss) | Earnings | Total | ||||||||||||||||||||||
Balance at December 31, 2002 |
81.0 | $ | 0.8 | $ | 594.8 | $ | | $ | (44.4 | ) | $ | 348.1 | $ | 899.3 | ||||||||||||||
Net income |
| | | | | 79.7 | 79.7 | |||||||||||||||||||||
Other comprehensive income |
||||||||||||||||||||||||||||
Currency translation adjustments |
| | | | 4.6 | | 4.6 | |||||||||||||||||||||
Derivative financial instruments |
| | | | (0.1 | ) | | (0.1 | ) | |||||||||||||||||||
Minimum liability of defined benefit plans |
| | | | (4.5 | ) | | (4.5 | ) | |||||||||||||||||||
Comprehensive income |
79.7 | |||||||||||||||||||||||||||
Stock issued for acquisition |
3.2 | 0.1 | 66.5 | | | | 66.6 | |||||||||||||||||||||
Stock options exercised |
0.9 | | 9.7 | | | | 9.7 | |||||||||||||||||||||
Tax benefit of options exercised |
| | 3.9 | | | | 3.9 | |||||||||||||||||||||
Balance at December 31, 2003 |
85.1 | $ | 0.9 | $ | 674.9 | $ | | $ | (44.4 | ) | $ | 427.8 | $ | 1,059.2 | ||||||||||||||
Net income |
| | | | | 115.2 | 115.2 | |||||||||||||||||||||
Other comprehensive income |
||||||||||||||||||||||||||||
Currency translation adjustments |
| | | | 71.3 | | 71.3 | |||||||||||||||||||||
Derivative financial instruments |
| | | | 1.1 | | 1.1 | |||||||||||||||||||||
Minimum liability of defined benefit plans |
| | | | 5.4 | | 5.4 | |||||||||||||||||||||
Comprehensive income |
193.0 | |||||||||||||||||||||||||||
Stock options exercised |
0.9 | | 14.6 | | | | 14.6 | |||||||||||||||||||||
Tax benefit of options exercised |
| | 3.4 | | | | 3.4 | |||||||||||||||||||||
Balance at December 31, 2004 |
86.0 | $ | 0.9 | $ | 692.9 | $ | | $ | 33.4 | $ | 543.0 | $ | 1,270.2 | |||||||||||||||
Net income |
| | | | | 286.9 | 286.9 | |||||||||||||||||||||
Other comprehensive income |
||||||||||||||||||||||||||||
Currency translation adjustments |
| | | | (50.3 | ) | | (50.3 | ) | |||||||||||||||||||
Derivative financial instruments |
| | | | (8.5 | ) | | (8.5 | ) | |||||||||||||||||||
Minimum liability of defined benefit plans |
| | | | 3.6 | | 3.6 | |||||||||||||||||||||
Comprehensive income |
231.7 | |||||||||||||||||||||||||||
Stock issued and stock options assumed for
acquisition |
84.0 | 0.8 | 2,566.5 | (32.1 | ) | | | 2,535.2 | ||||||||||||||||||||
Amortization of unearned stock-based
compensation |
| | | 15.6 | | | 15.6 | |||||||||||||||||||||
Common stock issued |
4.4 | | 111.8 | | | | 111.8 | |||||||||||||||||||||
Tax benefit of options exercised |
| | 29.7 | | | | 29.7 | |||||||||||||||||||||
Balance at December 31, 2005 |
174.4 | $ | 1.7 | $ | 3,400.9 | $ | (16.5 | ) | $ | (21.8 | ) | $ | 829.9 | $ | 4,194.2 | |||||||||||||
The accompanying notes are an integral part of these statements.
53
Table of Contents
NATIONAL OILWELL VARCO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
Basis of Consolidation
The accompanying consolidated financial statements include the accounts of National Oilwell Varco,
Inc. and its majority-owned subsidiaries. All significant intercompany transactions and balances
have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise
control, are fully consolidated with the equity held by minority owners and their portion of net
income (loss) reflected as minority interest in the accompanying financial statements. Investments
in unconsolidated affiliates, over which we exercise significant influence, but not control, are
accounted for by the equity method. Investments in which we exercise no control or significant
influence would be accounted for under the cost method. Certain reclassifications have been made
to the 2004 and 2003 consolidated financial statements in order for them to conform with the 2005
presentation.
2. Summary of Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and
payables approximated fair value because of the relatively short maturity of these instruments.
Cash equivalents include only those investments having a maturity date of three months or less at
the time of purchase. The carrying values of other financial instruments approximate their
respective fair values.
Derivative Financial Instruments
We record all derivative financial instruments at their fair value in our consolidated balance
sheet. All derivative financial instruments we hold are designated as either cash flow or fair
value hedges and are highly effective in offsetting movements in the underlying risks. Accordingly,
gains and losses from changes in the fair value of derivative financial instruments are deferred
and recognized in earnings as costs of sales as the underlying transactions occur. Because our
derivative financial instruments are so closely related to the underlying transactions, hedge
ineffectiveness is insignificant.
We use foreign currency forward contracts to mitigate our exposure to changes in foreign currency
exchange rates on forecasted transactions and firm sale commitments to better match the local
currency cost components of non-functional currency transactions. Such arrangements typically have
terms between three months and one year, but may have longer terms depending on the project and our
backlog. We may also use interest rate contracts to mitigate our exposure to changes in interest
rates on anticipated long-term debt issuances. These contracts are typically short term in nature.
We do not use derivative financial instruments for trading or speculative purposes.
At December 31, 2005, we had also entered into foreign currency forward contracts with notional
amounts aggregating $380.9 million to hedge exposure to currency fluctuations in various foreign
currencies, including the British Pound Sterling, the Euro, Norwegian Kroner and the Singapore
Dollar. These exposures arise when local currency operating expenses are not in balance with local
currency revenue collections. These foreign currency forward contracts are designated as cash flow
hedging instruments and are fully effective. Based on quoted market prices as of December 31, 2005
and 2004 for contracts with similar terms and maturity dates, we have recorded a gain(loss) of
($7.3) million and $1.4 million respectively to adjust these foreign currency forward contracts to
their fair market value. This gain(loss) is included in other comprehensive income in the
consolidated balance sheet. It is expected that $6.6 million of the loss will be reclassified into
earnings within the next 12 months. The Company currently has cash flow hedges in place through the
first quarter of 2008.
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The company also had several foreign currency forward contracts with notional amounts aggregating
$223.1 million designated and qualifying as fair value hedges to hedge exposure to the Euro,
Norwegian Kroner, and Singapore Dollar. Based on quoted market prices as of December 31, 2005 and
2004 for contracts with similar terms and maturity dates, we recorded a loss of $5.1 million and
$1.9 million respectively to adjust these foreign currency forward contracts to their fair market
value. This loss offsets designated gains on firm commitments.
Inventories
Inventories consist of oilfield products, manufactured equipment, specialized drilling products and
downhole motors and spare parts for manufactured equipment and drilling products. 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 $56.8 million and $41.2 million at
December 31, 2005 and 2004, is the amount necessary to reduce the cost of the inventory to its
estimated realizable value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for major improvements that
extend the lives of property and equipment are capitalized while minor replacements, maintenance
and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated
depreciation with any resulting gain or loss reflected in operations. Depreciation is provided
using the straight-line method or declining balance method over the estimated useful lives of
individual items. Depreciation expense was $83.0 million, $41.6 million and $37.4 million for the
years ending December 31, 2005, 2004 and 2003.
Long-lived Assets
We record impairment losses on long-lived assets used in operations when events and circumstances
indicate that the assets might be impaired and the undiscounted cash flows estimated to be
generated by those assets are less than the carrying amount of those assets. The carrying value of
assets used in operations that is not recoverable is reduced to fair value if lower than carrying
value. In determining the fair market value of the assets, we consider market trends and recent
transactions involving sales of similar assets, or when not available, discounted cash flow
analysis.
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Intangible Assets
On at least an annual basis, we assess whether goodwill is impaired. Our annual impairment tests
are performed at the beginning of the fourth quarter of each year and have indicated no impairment.
If we determine that goodwill is impaired, we measure that impairment based on the amount by
which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill
is determined by deducting the fair value of a reporting units identifiable assets and liabilities
from the fair value of that reporting unit as a whole. Additional impairment assessments may be
performed on an interim basis if we encounter events or changes in circumstances that would
indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value
of the reporting units is determined based on internal management estimates using a combination of
three methods: discounted cash flow, comparable companies and representative transactions.
Goodwill is identified by segment as follows (in millions):
Petroleum | ||||||||||||||||||||
Rig | Services & | Distribution | Corporate / | |||||||||||||||||
Technology | Supplies | Services | Eliminations | Total | ||||||||||||||||
Balance December 31, 2003 |
$ | 373.3 | $ | 173.3 | $ | 35.8 | $ | 4.9 | $ | 587.3 | ||||||||||
Additions to Goodwill |
31.1 | | (2.2 | ) | 1.2 | 30.1 | ||||||||||||||
Translation Adjustments |
20.0 | | 1.5 | 0.1 | 21.6 | |||||||||||||||
Balance December 31, 2004 |
424.4 | 173.3 | 35.1 | 6.2 | 639.0 | |||||||||||||||
Additions to Goodwill |
713.4 | 786.5 | (0.4 | ) | | 1,499.5 | ||||||||||||||
Translation Adjustments |
(20.6 | ) | (0.6 | ) | 0.3 | 0.1 | (20.8 | ) | ||||||||||||
Balance December 31, 2005 |
$ | 1,117.2 | $ | 959.2 | $ | 35.0 | $ | 6.3 | $ | 2,117.7 | ||||||||||
Identified intangible assets with determinable lives consist primarily of customer relationships,
trademarks, patents, and technical drawings acquired in the acquisitions of Varco, Hydralift, Mono
and Corlac, and are being amortized on a straight-line basis over the estimated useful lives of
10-30 years. The balance at December 31, 2005 and 2004 was $563 million and $36 million (net of
accumulated amortization of $36 million and $4 million, respectively). Amortization expense of
identified intangibles is expected to be approximately $38 million in each of the next five years.
Identified intangible assets with indefinite lives consist primarily of tradenames acquired in the
acquisitions of Varco, Hydralift, Mono and Corlac. The balance at December 31, 2005 and 2004 was $49
million and $55 million. Indefinite lived intangible assets are not amortized, but are subject to
an impairment test on at least an annual basis. An impairment charge would be recognized if the
fair value were determined to be less than the carrying amount. Our annual impairment tests have
indicated no impairment.
Petroleum | ||||||||||||||||||||
Rig | Services & | Distribution | Corporate / | |||||||||||||||||
Technology | Supplies | Services | Eliminations | Total | ||||||||||||||||
Balance December 31, 2003 |
$ | 69.1 | $ | 7.4 | $ | 2.8 | $ | | $ | 79.3 | ||||||||||
Additions to Intangible Assets |
6.3 | | | | 6.3 | |||||||||||||||
Amortization |
(1.8 | ) | | (0.5 | ) | | (2.3 | ) | ||||||||||||
Translation |
7.5 | | 0.2 | | 7.7 | |||||||||||||||
Balance December 31, 2004 |
81.1 | 7.4 | 2.5 | | 91.0 | |||||||||||||||
Additions to Intangible Assets |
217.4 | 341.9 | | | 559.3 | |||||||||||||||
Amortization |
(12.7 | ) | (18.5 | ) | (0.4 | ) | | (31.6 | ) | |||||||||||
Translation |
(7.3 | ) | | 0.1 | | (7.2 | ) | |||||||||||||
Balance December 31, 2005 |
$ | 278.5 | $ | 330.8 | $ | 2.2 | $ | | $ | 611.5 | ||||||||||
Deferred financing costs are amortized on a straight-line basis over the life of the related debt
securities.
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Foreign Currency
The functional currency for certain 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.
Revenues and expenses are translated at average exchange rates in effect during the period.
Certain other foreign operations use the U.S. dollar as the functional currency. Accordingly,
financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation
purposes using current rates of exchange for monetary assets and liabilities and historical rates
of exchange for nonmonetary assets and related elements of expense. Revenue and other expense
elements are remeasured at rates that approximate the rates in effect on the transaction dates. For
all operations, gains or losses from remeasuring foreign currency transactions into the functional
currency are included in income. Net foreign currency transaction gains (losses) were $2.9
million, ($9.3) million and ($7.2) million for the years ending December 31, 2005, 2004 and 2003,
respectively, and are included in other income(expense) in the accompanying statement of
operations.
Revenue Recognition
The Companys products and services are sold based upon purchase orders or contracts with the
customer that include fixed or determinable prices and that do not include right of return or other
similar provisions or other significant post delivery obligations. Except for certain construction
contracts 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, collectibility 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 costs 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 that are built or constructed to the customers specifications, and are manufactured
outside the Companys normal manufacturing process and marketed outside of the Companys normal
marketing channels. Projects recognized under the percentage-of-completion method include the
following characteristics: 1) the contracts include custom designs for customer specific
applications; 2) components are often modified with change orders throughout the project; 3) the
structural design is unique and requires significant engineering efforts; and 4) construction
projects often have progress payments. This method requires us to make estimates regarding the
total costs of the project, our progress against the project schedule and the estimated completion
date, all of which impact the amount of revenue and gross margin we recognize in each reporting
period. Changes in job performance, job conditions, and estimated profitability, including those
arising from contract penalty provisions, and final contract settlements may result in revisions to
costs and income and are recognized in the period in which the revisions are determined. Profit
incentives are included in revenues when their realization is reasonably assured. Provisions for
anticipated losses on uncompleted contracts are recorded in full when such losses become evident.
The Company measures the extent of progress towards completion on these projects using either input
or output based methods that are appropriate to the contract circumstances. The output methods are
based upon engineering estimates and the input measures are based upon the ratio of costs incurred
to the total projected costs.
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.
Income Taxes
The liability method is used to account for income taxes. Deferred tax assets and liabilities are
determined based on differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws 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 thorough 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. We
maintain an allowance for doubtful accounts for accounts receivables by
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providing for specifically identified accounts where collectibility is doubtful and an additional
allowance based on the aging of the receivables compared to past experience and current trends.
Accounts receivable are net of allowances for doubtful accounts of approximately $17.4 million and
$12.8 million at December 31, 2005 and 2004, respectively.
Stock-Based Compensation
We use the intrinsic value method in accounting for our stock-based employee compensation plans.
Assuming that we had accounted for our stock-based compensation using the alternative fair value
method of accounting under FAS No. 123 and amortized the fair value to expense over the options
vesting period, our net income and net income per share would have been (in millions, except per
share data):
Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Net income, as reported |
$ | 286.9 | $ | 115.2 | $ | 79.7 | ||||||
Add: |
||||||||||||
Total stock-based employee
compensation expense
included in net income,
net of related tax effects |
10.1 | | | |||||||||
Deduct: |
||||||||||||
Total stock-based employee
compensation expense
determined under fair
value based method for all
awards, net of related tax
effects |
(15.3 | ) | (7.4 | ) | (8.5 | ) | ||||||
Pro forma net income |
$ | 281.7 | $ | 107.8 | $ | 71.2 | ||||||
Net income per common
share: |
||||||||||||
Basic, as reported |
$ | 1.83 | $ | 1.34 | $ | 0.94 | ||||||
Basic, pro forma |
$ | 1.80 | $ | 1.26 | $ | 0.84 | ||||||
Diluted, as reported |
$ | 1.81 | $ | 1.33 | $ | 0.94 | ||||||
Diluted, pro forma |
$ | 1.78 | $ | 1.25 | $ | 0.84 | ||||||
These pro forma results may not be indicative of future effects.
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. Actual results could differ
from those estimates.
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Net Income Per Share
The following table sets forth the computation of weighted average basic and diluted shares
outstanding (in millions, except per share data):
Years Ended December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Numerator: |
||||||||||||
Net income |
$ | 286.9 | $ | 115.2 | $ | 79.7 | ||||||
Denominator: |
||||||||||||
Basicweighted average common shares outstanding |
156.4 | 85.8 | 84.5 | |||||||||
Dilutive effect of employee stock options |
1.9 | 0.7 | 0.5 | |||||||||
Diluted outstanding shares |
158.3 | 86.5 | 85.0 | |||||||||
Basic earnings per share |
$ | 1.83 | $ | 1.34 | $ | 0.94 | ||||||
Diluted earnings per share |
$ | 1.81 | $ | 1.33 | $ | 0.94 | ||||||
In addition, we had stock options outstanding that were anti-dilutive totaling nil at December 31,
2005, 0.8 million at December 31, 2004, and 2.3 million at December 31, 2003.
Recently Issued Accounting Standards
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, Inventory
Costs an amendment of ARB 43, Chapter 4 (SFAS 151). SFAS 151 clarifies the accounting for
abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph
5 of Accounting Research Bulletin (ARB) 43, Chapter 4 Inventory Pricing, previously stated
that under certain circumstances, items such as idle facility expense, excessive spoilage, double
freight, and rehandling costs may be so abnormal as to require treatment as current-period
charges. SFAS 151 requires that those items be recognized as current-period charges regardless of
whether they meet the criterion of so abnormal. In addition, SFAS 151 requires that the
allocation of fixed production overheads to the costs of conversion be based on the normal capacity
of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15,
2005. We do not believe the implementation of SFAS 151 will have a material impact on our
financial position, results of operations or cash flows.
In March 2005, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB)
No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123(R) and
certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of
share-based payment arrangements for public companies, including assumptions such as expected
volatility and expected term. We are assessing the impact SFAS No. 123(R) and SAB No. 107 will have
on our consolidated financial statements and which transition methods allowed by SFAS No. 123(R)
will be elected. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No.
123(R) for public companies. As a result, SFAS No. 123(R) will be effective for us on January 1,
2006.
In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations, (FIN 47) which clarifies when an
entity is required to recognize a liability for the fair value of a conditional asset retirement
obligation. FIN 47 will be effective for fiscal years ending after December 15, 2005, with earlier
adoption encouraged. We are currently evaluating the impact this interpretation may have on our
financial position, results of operations or cash flows.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, Accounting
Changes and Error Corrections (SFAS 154), which replaces APB Opinion No. 20, Accounting
Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154
requires a voluntary change in accounting principle to be applied retrospectively to all prior
period financial statements so that those financial statements are presented as if the current
accounting principle had always been applied. SFAS 154 is effective for accounting changes and
correction of errors made after January 1, 2006, with early adoption permitted. We do not expect
the adoption of SFAS 154 to have a material impact on our financial position, results of operations
or cash flows.
The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards No. 123R, Share-Based Payment (SFAS 123R), which originally required implementation for
interim or annual reporting periods beginning after June 15, 2005. However, in April 2005, the
Securities and Exchange Commission adopted a new rule to amend the compliance date to the beginning
of the Companys next fiscal year (January 1, 2006, for the Company). SFAS 123R requires us to
recognize the cost of employee services received in exchange for the companys equity instruments.
Currently, in accordance with APB
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Opinion 25, we record the intrinsic value of stock based compensation as expense. Accordingly, no
compensation expense is currently recognized for fixed stock option plans, except as described in
Notes 2 and 9 related to the Varco Merger, as the exercise price equals the stock price on the date
of grant. Under SFAS 123R, we will be required to measure compensation expense over the options
vesting period based on the stock options fair value at the date the options are granted and
classify the tax benefit from the exercise of nonqualified stock options as a financing activity in
the statement of cash flow. SFAS 123R allows for the use of the Black-Scholes or a lattice
option-pricing model to value such options. We will use the Black-Scholes option-pricing model to
calculate the fair value of the options. We have elected to adopt SFAS 123R on a modified
prospective basis. Note 2 illustrates the effects on net income and earnings per share if we had
adopted SFAS 123R using the Black-Scholes option-pricing model.
3. Varco Merger
Pursuant to our Amended and Restated Agreement and Plan of Merger with Varco International, Inc.
(Varco), a Delaware corporation, effective as of August 11, 2004 (the Agreement Date), we
issued 0.8363 shares of National Oilwell common stock for each Varco common share on March 11, 2005
(the Merger) and changed our name to National Oilwell Varco, Inc. We have included the financial
results of Varco in our consolidated financial statements beginning March 11, 2005 (the Merger
Date), the date Varco common shares were exchanged for National Oilwell common shares.
We believe our merger with Varco will better position us to compete more effectively in the global
marketplace and provide greater scale to increase service to our customers, increase our investment
in research and development to accelerate innovation, and increase stockholder value.
The Merger has been accounted for as a purchase business combination. Assets acquired and
liabilities assumed were recorded at their fair values as of March 11, 2005. The total preliminary
purchase price is $2,578.7 million, including the fair value of Varco stock options assumed and
estimated acquisition related transaction costs, and is comprised of (in millions):
Shares issued to acquire the outstanding common stock of Varco (84.0 million
shares at $29.99 per share) |
$ | 2,518.4 | ||
Fair value of Varco stock options assumed |
48.9 | |||
Unearned compensation related to stock options assumed |
(32.1 | ) | ||
Merger related transaction costs |
43.5 | |||
Total preliminary purchase price |
$ | 2,578.7 | ||
The fair value of shares issued was determined using an average price of $29.99, which represented
the average closing price of our common stock from five trading days before to five trading days
after the Agreement Date. The fair value of options assumed was calculated using the Black-Scholes
valuation model with the following assumptions as of the Merger Date: expected life from vest date
ranging from 0.64 years to 3.6 years, risk-free interest rate of 2.0% 3.1%, expected volatility
of 34% to 47% and no dividend yield. In accordance with our Agreement and Plan of Merger, the
number of Varco options exchanged was determined by multiplying the number of Varco options
outstanding at closing by 0.8363. Approximately 2.2 million of the 4.0 million Varco options
outstanding were fully vested as of the Merger. The portion of the intrinsic value of unvested
Varco options related to future service has been allocated to unearned compensation cost and is
being amortized using the remaining vesting period of 2.3 years. Stock-based compensation expense
of $15.6 million related to the amortization of the unvested options was recognized in the year
ended December 31, 2005.
Merger related transaction costs include severance and other external costs directly related to the
Merger.
Integration costs of $31.7 million in 2005 was comprised of $11.9 million for severance cost, $11.2
million for discontinued inventory, $4.8 million for combining operations and $3.8 million of
other.
Preliminary Purchase Price Allocation
Under the purchase method of accounting, the total preliminary purchase price was allocated to
Varcos net tangible and identifiable intangible assets based on their estimated fair values as of
March 11, 2005 as set forth below (in millions). The excess of the purchase price over the net
tangible and identifiable intangible assets was recorded as goodwill. The preliminary allocation of
the purchase price was based upon preliminary valuations and our estimates and assumptions are
subject to change upon the receipt and managements review of the final valuations. The primary
areas of the purchase price allocation which are not yet finalized relate to identifiable
intangible assets; property, plant and equipment; and goodwill. In addition, upon the finalization
of the combined companys legal entity structure, additional adjustments to deferred taxes may be
required. The final valuation of net assets is expected to be completed as soon as possible, but
no later than one year from the acquisition date in accordance with GAAP.
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Cash and marketable securities |
$ | 163.5 | ||
Trade receivables |
385.3 | |||
Other current assets |
28.5 | |||
Inventory |
377.1 | |||
Property, plant and equipment |
598.4 | |||
Goodwill, nondeductible |
1,492.4 | |||
Customer relationships (useful lives of 12-18
years) |
345.8 | |||
Trademarks (useful lives of 20-30 years) |
145.3 | |||
Patents (useful life of 10 years) |
60.2 | |||
Other non-current assets |
11.3 | |||
Accounts payable and accrued liabilities |
(223.9 | ) | ||
Income taxes payable |
(13.7 | ) | ||
Debt |
(492.8 | ) | ||
Deferred tax liabilities, net |
(249.5 | ) | ||
Other non-current liabilities |
(48.0 | ) | ||
Minority interest |
(1.2 | ) | ||
Total preliminary purchase price |
$ | 2,578.7 | ||
Pre-Acquisition Contingencies
We have currently not identified any material pre-merger contingencies where a liability is
probable and the amount of the liability can be reasonably estimated. If information becomes
available to us prior to the end of the purchase price allocation period, which would indicate that
it is probable that such events had occurred prior to the Merger Date and the amounts can be
reasonably estimated, such items will be included in the purchase price allocation.
Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of
operations of National-Oilwell and Varco, on a pro forma basis, as though the companies had been
combined as of the beginning of each of the periods presented. The pro forma financial information
is presented for informational purposes only and may not be indicative of the results of operations
that would have been achieved if the Merger had taken place at the beginning of each of the periods
presented. The pro forma financial information for the year ended December 31, 2005 includes
certain merger-related items of $47.3 million such as charges associated with integration expenses, stock-based
compensation charges for unvested options assumed, and severance expenses recorded by
National-Oilwell in its statements of operations related to change in control provisions that were
triggered as part of our Agreement and Plan of Merger in March 2005. The pro forma financial
information for all periods presented includes the business combination accounting effect on
historical Varco revenues, adjustments to depreciation on acquired property, and amortization
charges from acquired intangible assets, and related tax effects.
The unaudited pro forma financial information for the years ended December 31, 2005 and 2004
combines the historical results for National-Oilwell for the years ended December 31, 2005 and 2004
and the historical results for Varco for the years ended December 31, 2005 and 2004 (in millions):
December 31, | ||||||||
2005 | 2004 | |||||||
Total revenues |
$ | 4,952.4 | $ | 3,886.2 | ||||
Net income |
$ | 304.4 | $ | 201.8 | ||||
Basic net income per share |
$ | 1.76 | $ | 1.19 | ||||
Diluted net income per share |
$ | 1.74 | $ | 1.19 | ||||
4. Other Acquisitions
Year 2005
Excluding the Varco International, Inc. acquisition, the Company paid an aggregate purchase price
of $20.7 million ($16.0 million in cash and $4.7 million of notes payable) for acquisitions and
equity investments in 2005.
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Year 2004
We spent $2.8 million during 2004 acquiring assets or companies, with the largest being a
distribution operation in Australia.
Year 2003
On January 16, 2003, we acquired the Mono pumping products business from Halliburton Energy
Services for approximately $91 million, consisting of $24 million in cash and 3.2 million shares of
our common stock valued at $67 million. During the remainder of 2003 we made eight other
acquisitions representing cash outlays totaling $54 million primarily expanding our Distribution
network.
5. Inventories
At December 31, inventories consist of (in millions):
2005 | 2004 | |||||||
Raw materials and supplies |
$ | 220.4 | $ | 62.6 | ||||
Work in progress |
267.5 | 104.2 | ||||||
Finished goods and purchased products |
710.4 | 468.5 | ||||||
$ | 1,198.3 | $ | 635.3 | |||||
6. Property, Plant and Equipment
At December 31, property, plant and equipment consist of the following (in millions):
Estimated | ||||||||||||
Useful Lives | 2005 | 2004 | ||||||||||
Land and buildings |
2-31 Years | $ | 292.4 | $ | 138.6 | |||||||
Operating equipment |
3-12 Years | 729.9 | 276.0 | |||||||||
Rental equipment |
1-7 Years | 144.9 | 91.8 | |||||||||
1,167.2 | 506.4 | |||||||||||
Less accumulated depreciation |
(289.6 | ) | (251.3 | ) | ||||||||
$ | 877.6 | $ | 255.1 | |||||||||
7. Accrued Liabilities
At December 31, accrued liabilities consist of (in millions):
2005 | 2004 | |||||||
Compensation |
$ | 111.0 | $ | 37.0 | ||||
Warranty |
24.9 | 11.4 | ||||||
Interest |
11.7 | 9.4 | ||||||
Taxes (non income) |
23.6 | 12.0 | ||||||
Insurance |
30.2 | 8.8 | ||||||
Other |
153.8 | 71.0 | ||||||
Customer prepayments |
76.8 | 27.9 | ||||||
Billings in excess of costs |
98.1 | 32.0 | ||||||
Total |
$ | 530.1 | $ | 209.5 | ||||
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8. Costs and Estimated Earnings on Uncompleted Contracts
At December 31, costs and estimated earnings on uncompleted contracts consist of (in millions):
2005 | 2004 | |||||||
Costs incurred on uncompleted contracts |
$ | 1,440.9 | $ | 752.6 | ||||
Estimated earnings |
300.6 | 173.3 | ||||||
1,741.5 | 925.9 | |||||||
Less: Billings to date |
1,497.7 | 731.4 | ||||||
$ | 243.8 | $ | 194.5 | |||||
Costs and estimated earnings in excess of billings on uncompleted contracts |
$ | 341.9 | $ | 226.5 | ||||
Billings in excess of costs and estimated earnings on uncompleted contracts |
(98.1 | ) | (32.0 | ) | ||||
$ | 243.8 | $ | 194.5 | |||||
9. Long-Term Debt
At December 31, debt consists of (in millions):
2005 | 2004 | |||||||
$150.0 million Senior Notes, interest at 6.875% payable semiannually, principal due
on July 1, 2005 |
$ | | $ | 150.0 | ||||
$100.0 million Senior Notes, interest at 7.5% payable semiannually, principal due
on February 15, 2008 |
103.6 | | ||||||
$150.0 million Senior Notes, interest at 6.50% payable semiannually, principal due
on March 15, 2011 |
150.0 | 150.0 | ||||||
$200.0 million Senior Notes, interest at 7.25% payable semiannually, principal due
on May 1, 2011 |
218.7 | | ||||||
$200.0 million Senior Notes, interest at 5.65% payable semiannually, principal due
on November 15, 2012 |
200.0 | 200.0 | ||||||
$150.0 million Senior Notes, interest at 5.5% payable semiannually, principal due
on November 19, 2012 |
151.8 | | ||||||
Other |
17.2 | | ||||||
Total debt |
841.3 | 500.0 | ||||||
Less current portion |
5.7 | 150.0 | ||||||
Long-term debt |
$ | 835.6 | $ | 350.0 | ||||
Principal payments of debt for years subsequent to 2005 are as follows (in millions):
2006 |
$ | 5.7 | ||
2007 |
5.6 | |||
2008 |
105.4 | |||
2009 |
1.4 | |||
2010 |
1.4 | |||
Thereafter |
721.8 | |||
$ | 841.3 | |||
Senior Notes
Our $150 million of 6.875% unsecured senior notes were repaid on July 1, 2005 using available cash
balances. The Senior Notes contain reporting covenants and the credit facility contains financial
covenants regarding maximum debt to capitalization and minimum interest coverage. We were in
compliance with all covenants at December 31, 2005.
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Revolver Facilities
On June 21, 2005, we amended and restated our existing $150 million revolving credit facility with
a syndicate of lenders to provide the Company a $500 million unsecured revolving credit facility.
This facility will expire in July 2010, and replaces the Companys $175 million North American
revolving credit facility and our Norwegian facility. The Company has the right to increase the
facility to $750 million and to extend the term of the facility for an additional year. At
December 31, 2005, there were no borrowings against this facility, and there were $123 million in
outstanding letters of credit. Interest under this multicurrency facility is based upon LIBOR,
NIBOR, or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.
Other
Other debt includes approximately $15 million in promissory notes due to former owners of
businesses acquired who remain employed by the company.
At December 31, 2005, there were $377 million of funds available under the revolving credit
facility. The Company also has $139 million of additional outstanding letters of credit at
December 31, 2005 that are not secured by the Companys senior credit facility.
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, 2005, 2004 and 2003, expenses for
defined-contribution plans were $19.9 million, $14.2 million, and $13.1 million, and all funding is
current.
Certain retired or terminated employees of predecessor or acquired companies participate in a
defined benefit plan in the United States. None of the participants in this plan are eligible to
accrue benefits. In addition, approximately 456 U.S. retirees and spouses participate in defined
benefit health care plans of predecessor or acquired companies that provide postretirement medical
and life insurance benefits. Active employees are ineligible to participate in any of these defined
benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension
plans covering virtually all of their employees.
Net periodic benefit cost (credit) for our defined benefit pension plans in the United States, the
United Kingdom and Norway was as follows (in millions):
Pension benefits | Postretirement benefits | |||||||||||||||||||||||
For the year | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||||||||||||||||||
Service cost benefits earned during the period |
$ | 3.4 | $ | 2.9 | $ | 3.0 | $ | | $ | 0.1 | $ | | ||||||||||||
Interest cost on projected benefit obligation |
10.0 | 8.6 | 7.5 | 0.9 | 0.5 | 0.5 | ||||||||||||||||||
Expected return on plan assets |
(9.2 | ) | (8.8 | ) | (7.5 | ) | | | | |||||||||||||||
Net amortization and deferral |
1.5 | 1.5 | 1.4 | 0.2 | 0.2 | 0.2 | ||||||||||||||||||
Net periodic benefit cost |
$ | 5.7 | $ | 4.2 | $ | 4.4 | $ | 1.1 | $ | 0.8 | $ | 0.7 | ||||||||||||
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The change in benefit obligation, plan assets and the funded status of the defined benefit pension
plans in the United States, United Kingdom, and Norway and defined postretirement plans in the
United States, using a measurement date of December 31, 2005 or 2004, follows (in millions):
Postretirement | ||||||||||||||||
Pension benefits | benefits | |||||||||||||||
At year end | 2005 | 2004 | 2005 | 2004 | ||||||||||||
Benefit obligation at beginning of year |
$ | 158.4 | $ | 142.2 | $ | 7.3 | $ | 8.0 | ||||||||
Service cost |
3.4 | 2.9 | | 0.1 | ||||||||||||
Interest cost |
10.0 | 8.6 | 0.9 | 0.5 | ||||||||||||
Actuarial loss (gain) |
7.3 | (2.0 | ) | 1.2 | 0.2 | |||||||||||
Benefits paid |
(6.6 | ) | (5.6 | ) | (1.2 | ) | (0.7 | ) | ||||||||
Participant contributions |
0.8 | 0.8 | | | ||||||||||||
Acquisitions |
27.4 | | 10.8 | | ||||||||||||
Exchange rate (loss) gain |
(16.8 | ) | 11.5 | | | |||||||||||
Curtailments |
| | | (0.9 | ) | |||||||||||
Other |
| | | 0.1 | ||||||||||||
Benefit obligation at end of year |
$ | 183.9 | $ | 158.4 | $ | 19.0 | $ | 7.3 | ||||||||
Accumulated benefit obligation at end of year |
$ | 170.8 | $ | 149.5 | ||||||||||||
Fair value of plan assets at beginning of year |
$ | 135.3 | $ | 120.4 | $ | | $ | | ||||||||
Actual return |
20.1 | 7.2 | | | ||||||||||||
Benefits paid |
(5.8 | ) | (5.6 | ) | | (0.7 | ) | |||||||||
Contributions |
7.1 | 3.7 | | 0.7 | ||||||||||||
Exchange rate (loss) gain |
(14.1 | ) | 9.6 | | | |||||||||||
Fair value of plan assets at end of year |
$ | 142.6 | $ | 135.3 | $ | | $ | | ||||||||
Funded status |
$ | (31.3 | ) | $ | (21.5 | ) | $ | (18.5 | ) | $ | (7.2 | ) | ||||
Unrecognized actuarial net loss |
14.4 | 21.3 | 4.4 | 3.4 | ||||||||||||
Prior service costs not yet recognized |
0.1 | 0.2 | 0.1 | 0.1 | ||||||||||||
Prepaid (accrued) benefit cost |
$ | (16.8 | ) | $ | | $ | (14.0 | ) | $ | (3.7 | ) | |||||
Amounts recognized in the consolidated balance sheets consist of (in millions):
Pension benefits | Postretirement benefits | |||||||||||||||
2005 | 2004 | 2005 | 2004 | |||||||||||||
Prepaid benefit cost |
$ | 0.7 | $ | (0.2 | ) | $ | | $ | | |||||||
Accrued benefit cost |
(41.9 | ) | (31.9 | ) | (14.0 | ) | (3.7 | ) | ||||||||
Intangible assets |
0.1 | 0.2 | | | ||||||||||||
Accumulated other comprehensive income |
24.3 | 31.9 | | | ||||||||||||
Prepaid (accrued) benefit cost |
(16.8 | ) | | (14.0 | ) | (3.7 | ) | |||||||||
Pension asset valuation |
(10.5 | ) | (13.4 | ) | | | ||||||||||
Net amount recognized |
$ | (27.3 | ) | $ | (13.4 | ) | $ | (14.0 | ) | $ | (3.7 | ) | ||||
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Defined Benefit Pension Plans
Assumed long-term rates of return on plan assets, discount rates and rates of compensation
increases vary for the different plans according to the local economic conditions.
The assumption rates used for benefit obligations are as follows:
Years ending December 31, | ||||||||
2005 | 2004 | |||||||
Discount rate: |
||||||||
United States plan |
5.66 | % | 6.0 | % | ||||
International plans |
5.66 | % | 6.0 | % | ||||
Salary increase: |
||||||||
United States plan |
4.0 | % | N/A | |||||
International plans |
2.0 2.75 | % | 2.5 2.75 | % |
The assumption rates used for net periodic benefit costs are as follows:
Years ending December 31, | ||||||||||||
2005 | 2004 | 2003 | ||||||||||
Discount rate: |
||||||||||||
United States plan |
6.0 | % | 6.25 | % | 6.5 | % | ||||||
International plans |
6.0 | % | 6.0 | % | 5.75 6.0 | % | ||||||
Salary increase: |
||||||||||||
United States plan |
N/A | N/A | N/A | |||||||||
International plans |
2.5 2.75 | % | 2.5 | % | 2.5 4.0 | % | ||||||
Expected return on assets: |
||||||||||||
United States plan |
8.5 | % | 8.5 | % | 8.5 | % | ||||||
International plans |
6.25 7.17 | % | 6.5 7.75 | % | 6.5 7.75 | % |
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 weighted-average asset allocations at December 31, 2005 and 2004, by asset category are as
follows:
2005 | 2004 | |||||||||||||||
United States | International | United States | International | |||||||||||||
Equity securities |
59.5 | % | 48.6 | % | 59.4 | % | 56.5 | % | ||||||||
Fixed income |
35.5 | % | | 39.7 | % | | ||||||||||
Debt securities |
| 34.1 | % | | 28.7 | % | ||||||||||
Real estate |
| 5.1 | % | | 1.8 | % | ||||||||||
Other |
5.0 | % | 12.2 | % | 0.9 | % | 13.0 | % | ||||||||
Total |
100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||
In the U.S., our investment strategy includes a balanced approach with target allocation
percentages of 60% equity investments and 40% fixed income investments. Our target allocation
percentages in the United Kingdom plans are 50-60% equity securities and 40-50% debt securities.
The Norwegian target investment allocation percentage is 100% insurance contracts. Our pension
investment strategy worldwide prohibits a direct investment in our own stock.
Information for Pension Plans with Projected and Accumulated Benefit Obligations in Excess of Plan
Assets (in millions):
For year ending 2005 | For year ending 2004 | |||||||||||||||
United States | International | United States | International | |||||||||||||
Projected benefit obligation |
$ | 31.1 | $ | 87.6 | $ | 18.6 | $ | 60.4 | ||||||||
Accumulated benefit obligation |
30.8 | 80.1 | 18.6 | 58.8 | ||||||||||||
Fair value of assets |
14.3 | 59.8 | 12.8 | 45.8 |
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Additional Information for Defined Benefit Plans (in millions):
For year ending 2005 | For year ending 2004 | |||||||||||||||
United States | International | United States | International | |||||||||||||
Accumulated benefit obligation |
$ | 30.8 | $ | 80.1 | $ | 18.6 | $ | 58.8 | ||||||||
Change in minimum liability
included in other
comprehensive income, net of
tax |
0.2 | 3.4 | 0.9 | 4.5 |
In 2006, the Company expects to contribute $1.0 million in the U.S. and $7.0 million
internationally to its pension plans and $1.5 million to its other postretirement benefit plans.
In addition, the following benefit payments, which reflect expected future service, as appropriate,
are expected to be paid (in millions):
United | International | |||||||
States Plan | Plans | |||||||
2006 |
$ | 2.4 | $ | 4.8 | ||||
2007 |
2.4 | 4.9 | ||||||
2008 |
2.5 | 5.2 | ||||||
2009 |
2.6 | 5.5 | ||||||
2010 |
2.5 | 5.7 | ||||||
Subsequent five years |
11.1 | 33.2 |
Defined Benefit Healthcare Plans
Year ending | ||||||||
December 31, | ||||||||
Fiscal Period January 1 to December 31 | 2005 | 2004 | ||||||
Disclosure Assumptions |
||||||||
For determining benefit obligations at year-end |
||||||||
Discount rate |
5.66 | % | 6.0 | % | ||||
Salary increase |
5.0 | % | 5.0 | % | ||||
For determining net periodic cost for year |
||||||||
Discount rate |
5.78-6.0 | % | 6.25 | % | ||||
Salary increase |
5.0 | % | 5.0 | % | ||||
Expected return on assets |
N/A | N/A | ||||||
Measurement date |
9/30/2005 | 9/30/2004 | ||||||
Effect of 1% annual increase in health care cost trend rate: |
||||||||
Aggregate of the Service Cost and Interest Cost Dollar change |
$ | 0.08 | $ | 0.04 | ||||
APBO Dollar Change |
$ | 1.590 | $ | 0.625 | ||||
Effect of 1% annual decrease in health care cost trend rate: |
||||||||
Aggregate of the Service Cost and Interest Cost Dollar change |
$ | (0.07 | ) | $ | (0.035 | ) | ||
APBO Dollar Change |
$ | (1.363 | ) | $ | (0.526 | ) | ||
Cash Flows: |
||||||||
Employer contribution (expected during fiscal year beginning in 2006) |
$ | 1,547 | ||||||
Estimated future benefit payments during fiscal year ending (in millions): |
||||||||
2006 |
$ | 1.5 | ||||||
2007 |
1.5 | |||||||
2008 |
1.5 | |||||||
2009 |
1.5 | |||||||
2010 |
1.5 | |||||||
Subsequent five
years |
7.1 |
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The assumed weighted-average annual rate of increase in the per capita cost of covered benefits is
10.0% for 2006 and is assumed to decrease gradually to 5.0% for 2011 and remain at that level
thereafter. The health care cost trend rate assumption has a significant effect on the amounts
reported.
11. Accumulated Other Comprehensive Income / (Loss)
The components of other comprehensive income (loss) are as follows (in millions):
Change in | Cumulative | |||||||||||||||
Minimum | Currency | Derivative | ||||||||||||||
Pension | Translation | Financial | ||||||||||||||
Liability | Adjustment | Instruments | Total | |||||||||||||
Balance at December 31, 2002 |
$ | (12.9 | ) | $ | (32.4 | ) | $ | 0.9 | $ | (44.4 | ) | |||||
Current period activity |
(6.8 | ) | 4.6 | (0.1 | ) | (2.3 | ) | |||||||||
Tax effect |
2.3 | | | 2.3 | ||||||||||||
Balance at December 31, 2003 |
(17.4 | ) | (27.8 | ) | 0.8 | (44.4 | ) | |||||||||
Current period activity |
8.0 | 71.3 | 1.5 | 80.8 | ||||||||||||
Tax effect |
(2.6 | ) | | (0.4 | ) | (3.0 | ) | |||||||||
Balance at December 31, 2004 |
(12.0 | ) | 43.5 | 1.9 | 33.4 | |||||||||||
Current period activity |
4.7 | (50.3 | ) | (11.8 | ) | (57.4 | ) | |||||||||
Tax effect |
(1.1 | ) | | 3.3 | 2.2 | |||||||||||
Balance
at December 31, 2005 |
$ | (8.4 | ) | $ | (6.8 | ) | $ | (6.6 | ) | $ | (21.8 | ) | ||||
12. Commitments and Contingencies
We are involved in various claims, regulatory agency audits and pending or threatened legal actions
involving a variety of matters. The total liability on these matters at December 31, 2005 cannot be
determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided
for, should not materially affect our financial position, liquidity or results of operations.
Our business is affected both directly and indirectly by governmental laws and regulations relating
to the oilfield service industry in general, as well as by environmental and safety regulations
that specifically apply to our business. Although we have not incurred material costs in connection
with our compliance with such laws, there can be no assurance that other developments, such as
stricter environmental laws, regulations and enforcement policies thereunder could 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 2049. 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 $59.1 million, $22.4 million, and
$24.6 million in 2005, 2004 and 2003, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining
terms of one year or more at December 31, 2005 are payable as follows (in millions):
2006 |
$ | 52.8 | ||
2007 |
37.8 | |||
2008 |
27.7 | |||
2009 |
20.1 | |||
2010 |
15.1 | |||
Thereafter |
45.3 | |||
Total future lease commitments |
$ | 198.8 | ||
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Table of Contents
13. Common Stock
National Oilwell Varco has authorized 500 million shares of $.01 par value common stock. We also
have authorized 10 million shares of $.01 par value preferred stock, none of which is issued or
outstanding.
Under the terms of National Oilwell Varcos Long-Term Incentive Plan, as amended, 7.5 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 market price of
National Oilwell Varco common stock on the date of grant. At December 31, 2005, approximately 7.3
million shares were available for future grants.
We also have inactive stock option plans that were acquired in connection with the acquisitions of
Dreco Energy Services, Ltd. in 1997, IRI International Corporation in 2000 and Varco International,
Inc in March 2005. 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 and Long-Term
Incentive Plan and stock plans of acquired companies.
Options outstanding at December 31, 2005 under the stock option plans have exercise prices between
$8.82 and $58.25 per share, and expire at various dates from February 12, 2006 to October 13, 2015.
The following summarizes options activity:
Years Ended December 31, | ||||||||||||||||||||||||
2005 | 2004 | 2003 | ||||||||||||||||||||||
Average | Average | Average | ||||||||||||||||||||||
Number of | Exercise | Number of | Exercise | Number of | Exercise | |||||||||||||||||||
shares | Price | shares | Price | shares | Price | |||||||||||||||||||
Shares under option at beginning
of year |
3,732,316 | $ | 26.69 | 3,610,571 | $ | 23.83 | 3,790,496 | $ | 21.99 | |||||||||||||||
Granted |
5,292,074 | 28.88 | 1,142,500 | 28.22 | 1,035,000 | 20.05 | ||||||||||||||||||
Cancelled |
(452,098 | ) | 27.95 | (96,570 | ) | 27.91 | (304,659 | ) | 28.01 | |||||||||||||||
Exercised |
(4,231,450 | ) | 25.41 | (924,185 | ) | 17.28 | (910,266 | ) | 10.47 | |||||||||||||||
Shares under option at end of year |
4,340,842 | 30.36 | 3,732,316 | $ | 26.69 | 3,610,571 | $ | 23.83 | ||||||||||||||||
Exercisable at end of year |
913,558 | $ | 23.77 | 1,657,162 | $ | 29.66 | 1,713,647 | $ | 25.47 | |||||||||||||||
The following summarizes information about stock options outstanding as of December 31, 2005:
Weighted-Avg | Options Outstanding | Options Exercisable | ||||||||||||||||||
Range of | Remaining | Weighted-Avg | Weighted-Avg | |||||||||||||||||
Exercise Price | Contractual Life | Shares | Exercise Price | Shares | Exercise Price | |||||||||||||||
$8.82 to $19.39 |
5.27 | 251,178 | 16.09 | 248,678 | 16.05 | |||||||||||||||
$20.07 to $28.22 |
7.48 | 2,081,342 | 24.71 | 541,578 | 23.70 | |||||||||||||||
$33.00 to $58.25 |
8.85 | 2,008,322 | 38.01 | 123,302 | 39.60 | |||||||||||||||
Totals |
7.99 | 4,340,842 | 30.36 | 913,558 | 23.77 | |||||||||||||||
The weighted average fair value of options granted during 2005, 2004 and 2003 was approximately
$16.85 (excluding options assumed in the Varco merger), $13.19, and $8.88 per share, as determined
using the Black-Scholes option-pricing model.
The assumptions used in the Black-Scholes option-pricing model were:
Assumptions | 2005 | 2004 | 2003 | |||||||||
Risk-free interest rate |
3.7 | % | 2.7 | % | 2.6 | % | ||||||
Expected dividend |
| | | |||||||||
Expected option life (years) |
5 | 5 | 5 | |||||||||
Expected Volatility |
46 | % | 51 | % | 48 | % |
On February 21, 2006, we granted 2,344,000 stock options at an exercise price of $66.58.
69
Table of Contents
14. Income Taxes
The domestic and foreign components of income before income taxes were as follows (in millions):
December 31, | December 31, | December 31, | ||||||||||
2005 | 2004 | 2003 | ||||||||||
Domestic |
$ | 213.6 | $ | 51.5 | $ | 24.2 | ||||||
Foreign |
216.4 | 87.4 | 97.6 | |||||||||
$ | 430.0 | $ | 138.9 | $ | 121.8 | |||||||
The components of the provision for income taxes consisted of (in millions):
December 31, | December 31, | December 31, | ||||||||||
2005 | 2004 | 2003 | ||||||||||
Current: |
||||||||||||
Federal |
$ | 70.5 | $ | 9.8 | $ | 5.5 | ||||||
State |
2.8 | (3.3 | ) | 0.9 | ||||||||
Foreign |
67.6 | 21.8 | 22.6 | |||||||||
140.9 | 28.3 | 29.0 | ||||||||||
Deferred: |
||||||||||||
Federal |
2.6 | (12.8 | ) | 1.7 | ||||||||
State |
(0.7 | ) | 2.2 | 0.7 | ||||||||
Foreign |
(3.9 | ) | 3.9 | 4.5 | ||||||||
(2.0 | ) | (6.7 | ) | 6.9 | ||||||||
$ | 138.9 | $ | 21.6 | $ | 35.9 | |||||||
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):
December 31, | December 31, | December 31, | ||||||||||
2005 | 2004 | 2003 | ||||||||||
Federal income tax at statutory rate |
$ | 150.5 | $ | 48.6 | $ | 42.6 | ||||||
Foreign income tax rate differential |
(13.3 | ) | (2.3 | ) | (7.9 | ) | ||||||
State income tax, net of federal
benefit |
1.4 | 1.0 | 0.6 | |||||||||
Tax benefit of foreign sales income |
(6.8 | ) | (3.1 | ) | (3.0 | ) | ||||||
Nondeductible expenses |
5.0 | 1.3 | 1.7 | |||||||||
Tax benefit of capital loss carryovers |
| | (0.8 | ) | ||||||||
Foreign dividends net of FTCs |
6.2 | 3.2 | (2.7 | ) | ||||||||
Net operating loss carryforwards |
| | (0.7 | ) | ||||||||
Change in deferred tax valuation
allowance |
(4.4 | ) | (20.1 | ) | 6.9 | |||||||
Prior year taxes |
(2.1 | ) | (7.2 | ) | (0.8 | ) | ||||||
Other |
2.4 | 0.2 | | |||||||||
$ | 138.9 | $ | 21.6 | $ | 35.9 | |||||||
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Significant components of our deferred tax assets and liabilities were as follows (in millions):
December 31, | December 31, | |||||||
2005 | 2004 | |||||||
Deferred tax assets: |
||||||||
Allowances and operating liabilities |
$ | 62.4 | $ | 19.6 | ||||
Net operating loss carryforwards |
11.8 | 18.6 | ||||||
Foreign tax credit carryforwards |
4.8 | 21.1 | ||||||
Capital loss carryforward |
0.2 | 3.8 | ||||||
Other |
33.5 | 24.3 | ||||||
Total deferred tax assets |
112.7 | 87.4 | ||||||
Valuation allowance for deferred tax assets |
(1.9 | ) | (16.8 | ) | ||||
110.8 | 70.6 | |||||||
Deferred tax liabilities: |
||||||||
Tax over book depreciation |
98.2 | 29.6 | ||||||
Intangible assets |
215.5 | 26.7 | ||||||
Deferred income |
15.6 | 32.0 | ||||||
Other |
44.0 | 14.5 | ||||||
Total deferred tax liabilities |
373.3 | 102.8 | ||||||
Net deferred tax asset (liability) |
$ | (262.5 | ) | $ | (32.2 | ) | ||
In the United States, the Company has $17.7 million of net operating loss carryforwards as of
December 31, 2005, which expire at various dates through 2021. The potential benefit of $6.4
million has been recorded with no valuation allowance. Future income tax payments will be reduced
when the Company ultimately realizes the benefit of these net operating losses.
Also in the United States, the Company had $9.8 million of capital loss carryforwards as of
December 31, 2004 which expired in 2005. The related potential benefit of $3.8 million had been
recorded with a full valuation allowance of $3.8 million. These capital losses were not realized
before they expired. Tax expense was not affected by the expiration of these capital losses. The
Company has $4.8 million of foreign tax credit carryforwards as of December 31, 2005, which expire at
various dates through 2014. These credits have not been allotted a valuation allowance and will be
realized as a reduction of future income tax payments.
Outside the United States, the company has $19.7 million of net operating loss carryforwards as of
December 31, 2005. Of this amount, $6.4 million will expire at various dates through 2012 and
$13.3 million is available indefinitely. The related potential benefit available of $5.4 million
has been recorded with a valuation allowance of $1.7 million. If the Company ultimately realizes
the benefit of these net operating losses, the valuation allowance of $1.1 million would reduce
income tax expense and $0.6 million will reduce goodwill.
Also outside the United States, the company has $0.6 million of capital loss carryforwards as of
December 31, 2005, which can be carried forward indefinitely. The related potential benefit of
$0.2 million has been recorded with a full valuation allowance of $0.2 million. These capital
losses are not available to reduce future operating income but if realized will reduce future
capital gains and will result in a reduction of future income tax expense.
The deferred tax valuation allowance decreased $14.9 million and $20.1 million for the periods
ending December 31, 2005 and 2004. Of the net decrease recorded in 2005, $4.4 million was recorded as a
reduction of income tax expense and $18.1 million as a reduction of goodwill. These decreases were
partially offset by an increase in deferred tax valuation allowances of $7.6 million due to
exchange rate movements in foreign jurisdictions. The decrease in 2004 was reflected as a
reduction of tax expense and resulted primarily from completion of certain acquisition financing
transactions and the enactment of the American Jobs Creation Act of 2004, which extended the
carryforward period of foreign tax credit carryforwards in the United States. The Companys deferred
tax assets are expected to be realized principally through future earnings.
Undistributed earnings of the Companys foreign subsidiaries amounted to $441.4 million and $299.9
million at December 31, 2005 and 2004. Those earnings are considered to be permanently reinvested
and no provision for U.S. federal and state income taxes has been made. Distribution of these
earnings in the form of dividends or otherwise could result in either U.S. federal taxes (subject
to an adjustment for foreign tax credits) and withholding taxes payable in various foreign
countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not
practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some
portion of the U.S. liability. Withholding taxes of approximately $31.5 million would be payable
upon remittance of all previously unremitted earnings at December 31, 2005.
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Table of Contents
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
Companys future tax provision will reflect any favorable or unfavorable adjustments to its
estimated tax liabilities when resolved. The Company is unable to predict the outcome of these
matters. However, we believe that none of these matters will have a material adverse effect on the
results of operations or financial condition of the Company.
In October 2004, the American Jobs Creation Act of 2004 (the Jobs Act) was signed into law which
introduced a special one-time dividends received deduction on the repatriation of foreign earnings
to a U.S. taxpayer (repatriation provision), provided certain criteria are met. The Act provides
for a special one-time deduction of 85 percent of certain foreign earnings that are repatriated in
either the Companys last tax year that began before the enactment date, or the first tax year that
begins during the one-year period beginning on the date of enactment. The maximum amount of the
Companys foreign earnings that qualify for temporary deduction is $408.2 million. The Company
repatriated none of its foreign earnings in 2004 or 2005 under the repatriation provisions of the
Jobs Act.
15. Business Segments and Geographic Areas
The Companys operations consist of three reportable segments: Rig Technology, Petroleum Services &
Supplies and Distribution Services.
Rig Technology: Our Rig Technology Group designs, manufactures, sells and services complete rig
systems for the drilling, completion, and remediation of oil and gas wells. The Group offers a
comprehensive line of highly-engineered machinery which automates complex well construction and
management operations, such as offshore and onshore drilling rigs; pipe racking, rotating and
assembly systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline
winches; and cranes.
Petroleum Services & Supplies: Our Petroleum Services & Supplies Group provides a variety of
consumable goods and services used to drill, complete, remediate and workover oil and gas wells,
and manage pipelines, flowlines and other oilfield tubular goods. The Group manufactures, rents
and sells a variety of products and equipment used to perform drilling operations, including solids
control systems, drilling motors, rig instrumentation systems, and drilling mud pump consumables.
Distribution Services: Our Distribution Services Group provides maintenance, repair and operating
supplies and spare parts to drill site and production locations worldwide. In addition to its
comprehensive network of field locations supporting land drilling operations throughout North
America, the Group supports major offshore drilling contractors through locations in the Middle
East, Europe, Southeast Asia and South America. The Group employs advanced information
technologies to provide complete procurement, inventory management and logistics services to its
customers around the globe.
The accounting policies of the reportable segments are the same as those described in the summary
of significant accounting policies of the Company. The Company evaluates performance of each
reportable segment based upon its operating income, excluding non-recurring items.
No single customer accounted for 10% or more of consolidated revenues during the three years ended
December 31, 2005.
Summarized financial information is as follows (in millions):
Geographic Areas:
United | United | |||||||||||||||||||||||
States | Canada | Norway | Kingdom | Other | Total | |||||||||||||||||||
December 31, 2005 |
||||||||||||||||||||||||
Revenues |
$ | 2,646.6 | $ | 653.6 | $ | 394.8 | $ | 298.0 | $ | 651.5 | $ | 4,644.5 | ||||||||||||
Long-lived assets |
584.1 | 82.7 | 32.6 | 57.1 | 121.1 | 877.6 | ||||||||||||||||||
December 31, 2004 |
||||||||||||||||||||||||
Revenues |
$ | 1,303.6 | $ | 403.1 | $ | 274.1 | $ | 99.7 | $ | 237.6 | $ | 2,318.1 | ||||||||||||
Long-lived assets |
126.1 | 33.2 | 33.1 | 24.4 | 38.3 | 255.1 | ||||||||||||||||||
December 31, 2003 |
||||||||||||||||||||||||
Revenues |
$ | 1,086.7 | $ | 332.9 | $ | 260.2 | $ | 95.9 | $ | 229.2 | $ | 2,004.9 | ||||||||||||
Long-lived assets |
133.9 | 32.4 | 29.5 | 22.8 | 33.8 | 252.4 |
72
Table of Contents
Business Segments
Petroleum | ||||||||||||||||||||
Services & | Distribution | Unallocated/ | ||||||||||||||||||
Rig Technology | Supplies | Services | Eliminations | Total | ||||||||||||||||
December 31, 2005 |
||||||||||||||||||||
Revenues |
$ | 2,216.8 | $ | 1,645.8 | $ | 1,074.5 | $ | (292.6 | ) | $ | 4,644.5 | |||||||||
Operating profit (a) |
247.7 | 300.1 | 46.6 | (70.3 | ) | 524.1 | ||||||||||||||
Capital expenditures |
22.9 | 72.6 | 3.7 | 5.8 | 105.0 | |||||||||||||||
Depreciation and amortization |
35.4 | 68.9 | 5.4 | 4.9 | 114.6 | |||||||||||||||
Goodwill |
1,117.2 | 959.2 | 35.0 | 6.3 | 2,117.7 | |||||||||||||||
Total assets |
3,310.3 | 2,717.5 | 479.7 | 171.0 | 6,678.5 | |||||||||||||||
December 31, 2004 |
||||||||||||||||||||
Revenues |
$ | 1,085.5 | $ | 505.5 | $ | 905.1 | $ | (178.0 | ) | $ | 2,318.1 | |||||||||
Operating profit |
102.4 | 62.7 | 29.6 | (18.7 | ) | 176.0 | ||||||||||||||
Capital expenditures |
15.3 | 19.5 | 2.3 | 1.9 | 39.0 | |||||||||||||||
Depreciation and amortization |
16.2 | 18.5 | 6.8 | 2.5 | 44.0 | |||||||||||||||
Goodwill |
424.4 | 173.3 | 35.1 | 6.2 | 639.0 | |||||||||||||||
Total assets |
1,329.5 | 720.4 | 386.5 | 140.1 | 2,576.5 | |||||||||||||||
December 31, 2003 |
||||||||||||||||||||
Revenues |
$ | 880.1 | $ | 446.3 | $ | 792.0 | $ | (113.5 | ) | $ | 2,004.9 | |||||||||
Operating profit |
96.8 | 73.7 | 6.5 | (12.9 | ) | 164.1 | ||||||||||||||
Capital expenditures |
9.9 | 15.6 | 3.8 | 3.1 | 32.4 | |||||||||||||||
Depreciation and amortization |
13.4 | 16.7 | 5.8 | 3.3 | 39.2 | |||||||||||||||
Goodwill |
373.3 | 173.3 | 35.8 | 4.9 | 587.3 | |||||||||||||||
Total assets |
1,074.3 | 688.8 | 363.7 | 86.3 | 2,213.1 |
(a) | Excludes $47.3 million of integration costs and stock-based compensation. | |
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data). The 2005
results include Varco operations from the acquisition date of March 11, 2005:
First | Second | Third | Fourth | |||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Total | ||||||||||||||||
Year ended December 31, 2005 |
||||||||||||||||||||
Revenues |
$ | 814.9 | $ | 1,215.7 | $ | 1,236.5 | $ | 1,377.4 | $ | 4,644.5 | ||||||||||
Gross Profit |
161.8 | 255.2 | 258.7 | 311.5 | 987.2 | |||||||||||||||
Net income |
35.6 | 61.2 | 88.5 | 101.6 | 286.9 | |||||||||||||||
Net income per basic share |
0.34 | 0.35 | 0.51 | 0.58 | 1.83 | |||||||||||||||
Net income per diluted share |
0.33 | 0.35 | 0.50 | 0.58 | 1.81 | |||||||||||||||
Year ended December 31, 2004 |
||||||||||||||||||||
Revenues |
$ | 496.2 | $ | 533.5 | $ | 618.9 | $ | 669.5 | $ | 2,318.1 | ||||||||||
Gross Profit |
104.4 | 119.5 | 133.0 | 146.9 | 503.8 | |||||||||||||||
Net income |
11.6 | 22.6 | 28.4 | 52.6 | 115.2 | |||||||||||||||
Net income per basic share |
0.14 | 0.26 | 0.33 | 0.61 | 1.34 | |||||||||||||||
Net income per diluted share |
0.14 | 0.26 | 0.33 | 0.61 | 1.33 |
73
Table of Contents
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2005, 2004, and 2003
VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 2005, 2004, and 2003
Additions | ||||||||||||||||
(Deductions) | Charge | |||||||||||||||
Balance | charged to | offs | Balance | |||||||||||||
beginning | costs and | and | end of | |||||||||||||
of year | expenses | other | year | |||||||||||||
(in millions) | ||||||||||||||||
Allowance for doubtful accounts: |
||||||||||||||||
2005 |
$ | 12.8 | $ | 7.8 | $ | (3.2 | ) | $ | 17.4 | |||||||
2004 |
18.3 | 4.0 | (9.5 | ) | 12.8 | |||||||||||
2003 |
12.6 | 5.7 | | 18.3 | ||||||||||||
Valuation allowance for deferred tax assets: |
||||||||||||||||
2005 |
$ | 16.8 | $ | (4.4 | ) | $ | (10.5 | ) | $ | 1.9 | ||||||
2004 |
36.9 | (20.3 | ) | 0.2 | 16.8 | |||||||||||
2003 |
29.9 | 7.0 | | 36.9 |
74
Table of Contents
EXHIBIT
INDEX
2.1
|
Amended and Restated Agreement and Plan of Merger, effective as of August 11, between National-Oilwell, Inc. and Varco International, Inc. (4). | |
3.1
|
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1). | |
3.2
|
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.2) (7). | |
10.1
|
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2). | |
10.2
|
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreements with Kevin A. Neveu and Mark A. Reese. (Exhibit 10.2) (2). | |
10.3
|
Form of Amended and Restated Executive Agreement of Clay C. Williams and Haynes Smith. (Exhibit 10.12) (3). | |
10.4
|
National Oilwell Varco Long-Term Incentive Plan (5)*. | |
10.5
|
Form of Employee Stock Option Agreement (Exhibit 10.1) (8) | |
10.6
|
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (8). | |
10.7
|
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6). | |
21.1
|
Subsidiaries of the Company. | |
23.1
|
Consent of Ernst & Young LLP | |
24.1
|
Power of Attorney (included on signature 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. |
* | Compensatory plan or arrangement for management or others | |
(1) | Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000. | |
(2) | Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002. | |
(3) | Filed as an Exhibit to Varco International, Inc.s Quarterly Report on Form 10-Q filed on May 6, 2004. | |
(4) | Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004. | |
(5) | Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005. | |
(6) | Filed as an Exhibit to our Current Report on Form 8-K filed on June 23, 2005. | |
(7) | Filed as an Exhibit to our Current Report on Form 8-K filed on November 18, 2005. | |
(8) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006. |