e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008 |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-9397
Baker Hughes Incorporated
(Exact name of registrant as specified in its charter)
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Delaware
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76-0207995 |
(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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2929 Allen Parkway, Suite 2100, Houston, Texas
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77019-2118 |
(Address of principal executive offices)
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(Zip Code) |
Registrants telephone number, including area code: (713) 439-8600
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
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Common Stock, $1 Par Value per Share
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New York Stock Exchange |
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SWX Swiss Exchange |
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 o NO þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or 15(d) of the Exchange 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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange
Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a
smaller reporting company) |
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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 the voting and non-voting common stock held by non-affiliates as
of the last business day of the registrants
most recently completed second fiscal quarter (based
on the closing price on June 30, 2008 reported by the New
York Stock Exchange) was
approximately
$26,994,000,000.
As of February 20, 2009, the registrant has outstanding 308,874,934 shares of common stock, $1
par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrants Definitive Proxy Statement for the Annual Meeting of Stockholders to
be held April 23, 2009 are incorporated by
reference into Part III of this Form 10-K.
Baker Hughes Incorporated
INDEX
1
PART I
ITEM 1. BUSINESS
Baker Hughes Incorporated is a Delaware corporation engaged in the oilfield services industry.
As used herein, Baker Hughes, Company, we, our and us may refer to Baker Hughes
Incorporated and/or its subsidiaries. The use of these terms is not intended to connote any
particular corporate status or relationships. Baker Hughes was formed in April 1987 in connection
with the combination of Baker International Corporation and Hughes Tool Company. We are a major
supplier of wellbore related products and technology services, including products and services for
drilling, formation evaluation, completion and production and reservoir technology and consulting
to the worldwide oil and natural gas industry. We may conduct our operations through subsidiaries,
affiliates, ventures and alliances.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended (the Exchange Act), are made available free of charge
on our Internet website at www.bakerhughes.com as soon as reasonably practicable after these
reports have been electronically filed with, or furnished to, the Securities and Exchange
Commission (the SEC). Information contained on or connected to our website is not incorporated
by reference into this annual report on Form 10-K and should not be considered part of this report
or any other filing we make with the SEC.
We have adopted a Business Code of Conduct to provide guidance to our directors, officers and
employees on matters of business conduct and ethics, including compliance standards and procedures.
We have also required our principal executive officer, principal financial officer and principal
accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct
and Code of Ethical Conduct Certifications are available on the Investor Relations section of our
website at www.bakerhughes.com. We will disclose on a current report on Form 8-K or on our website
information about any amendment or waiver of these codes for our executive officers and directors.
Waiver information disclosed on our website will remain on the website for at least 12 months after
the initial disclosure of a waiver. Our Corporate Governance Guidelines and the charters of our
Audit/Ethics Committee, Compensation Committee, Executive Committee, Finance Committee and
Governance Committee are also available on the Investor Relations section of our website at
www.bakerhughes.com. In addition, a copy of our Business Code of Conduct, Code of Ethical Conduct
Certifications, Corporate Governance Guidelines and the charters of the committees referenced above
are available in print at no cost to any stockholder who requests them by writing or telephoning us
at the following address or telephone number:
Baker Hughes Incorporated
2929 Allen Parkway, Suite 2100
Houston, TX 77019-2118
Attention: Investor Relations
Telephone: (713) 439-8039
We report our results under two segments: the Drilling and Evaluation segment and the
Completion and Production segment. We have aggregated our divisions within each segment by
aligning our product lines based upon the types of products and services provided to our customers
and upon the business characteristics of the product lines during business cycles. The product
lines have similar economic characteristics and the long-term financial performance of these
product lines are affected by similar economic conditions. They also operate in the same markets,
which include all of the major oil and natural gas producing regions of the world.
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The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids
(drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling,
measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation
evaluation and wireline completion services) divisions and also includes our reservoir
technology and consulting group. The Drilling and Evaluation segment provides products and
services used to drill and evaluate oil and natural gas wells and consulting services used
in the analysis of oil and gas reservoirs. |
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The Completion and Production segment consists of the Baker Oil Tools (workover, fishing
and completion equipment), Baker Petrolite (oilfield specialty chemicals), Centrilift
(electric submersible pumps and progressing cavity pumps) divisions, the ProductionQuest
(production optimization and permanent monitoring) business unit, and Integrated Operations
and Project Management. The Completion and Production segment provides equipment and
services used from the completion phase through the productive life of oil and natural gas
wells. |
For additional industry segment information for the three years ended December 31, 2008, see
Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.
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DRILLING AND EVALUATION SEGMENT
Our Drilling and Evaluation segment is a leading provider of products and services used in the
drilling and evaluation of oil and natural gas wells. We provide drilling and completion fluids
and fluids environmental services, Tricone® roller cone bits and fixed-cutter polycrystalline
diamond compact (PDC) bits , directional drilling services, measurement-while-drilling (MWD)
and logging-while-drilling (LWD) services, wireline formation evaluation and completion and
production services, and reservoir technology and consulting services.
Drilling Fluids
Drilling fluids (also called Mud) are an important component of the drilling process and are
pumped from the surface through the drill string, exiting nozzles in the drill bit and traveling
back up the wellbore where the fluids are recycled. This process cleans the bottom of the well by
transporting the cuttings to the surface while also cooling and lubricating the bit and drill
string. Drilling fluids are typically manufactured by mixing oil, synthetic fluids or water with
barite to give them weight, which enables the fluids to hold the wellbore open and stabilize it.
Additionally, the fluids control downhole pressure and seal porous sections of the wellbore. To
ensure maximum efficiency and wellbore stability, chemical additives are blended by the wellsite
engineer with drilling fluids to achieve particular physical or chemical characteristics. For
drilling through the reservoir itself, drill-in or completion fluids (also called brines) possess
properties that minimize formation damage. Fluids environmental services (also called waste
management) is the process of separating the drill cuttings from the drilling fluids and
re-injecting the processed cuttings into specially prepared wells, or transporting and disposing of
the cuttings by other means.
Technology is very important in the selection of drilling fluids for many drilling programs,
especially in deepwater, deep drilling and environmentally sensitive areas, whereas cost efficiency
tends to drive customer purchasing decisions in other areas. Specific opportunities for
competitive differentiation include:
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improving drilling efficiency, |
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minimizing formation damage, and |
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handling and disposing of drilling fluids and cuttings in an environmentally safe
manner. |
Key business drivers for drilling and completion fluids and fluids environmental services
include the number of drilling rigs operating (especially the number of drilling programs targeting
deep formations), total footage drilled, environmental regulations, as well as the current and
expected future price of both oil and natural gas. Our primary competitors include M-I SWACO,
Halliburton Company (Halliburton) and Newpark Resources, Inc.
Drill Bits
We are a leading supplier of tri-cone and diamond drill bits. The primary objective of a
drill bit is to drill a high quality wellbore as efficiently as possible. There are two primary
types of drill bits:
Tricone® Bits. Tricone® drill bits employ either hardened steel teeth or tungsten carbide
insert cutting structures mounted on three rotating cones. These bits work by crushing and
shearing the formation rock as they are turned. Tricone® drill bits have a wide application range.
PDC (also known as Diamond) bits use fixed position cutters that shear the formation rock
with a milling action as they are turned. In many softer and less variable applications, PDC bits
offer higher penetration rates and a longer life than Tricone® drill bits. Advances in PDC
technology have expanded the application of PDC bits into harder, more abrasive formations. A
rental market has developed for PDC bits as improvements in bit life and bit repairs allow a bit to
be used to drill multiple wells.
The main driver of customer purchasing decisions in drill bits is the value added, usually
measured in terms of savings in total operating costs per foot drilled. Specific opportunities for
competitive differentiation include:
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improving the rate of penetration, |
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extending bit life and bit reliability, and |
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selecting the optimal bit for each section to be drilled. |
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Key business drivers for the sale or rental of drill bits include the number of drilling rigs
operating, total footage drilled, type of well drilled (vertical, deviated, horizontal or extended
reach), drilling rig rental costs, as well as the current and expected future price of both oil and
natural gas. Our primary competitors in the oil and natural gas drill bit market include Smith
International, Inc. (Smith), National Oilwell Varco, Inc. and Halliburton.
Directional Drilling and Drilling Evaluation Services
We are a leading supplier of drilling and evaluation services, which include directional
drilling, MWD and LWD services.
Directional Drilling. Directional drilling services are used to guide a drill string along a
predetermined path to drill a wellbore to optimally recover hydrocarbons from the reservoir. These
services are used to accurately drill vertical wells, deviated or directional wells (which deviate
from vertical by a planned angle and direction), horizontal wells (which are sections of wells
drilled perpendicular or nearly perpendicular to vertical) and extended reach wells.
We provide both conventional and rotary based directional drilling systems. Conventional
directional drilling systems employ a downhole motor that turns the drill bit independently of
drill string rotation from the surface. Placed just above the bit, a steerable motor assembly has
a bend in its housing that is oriented to steer the wells course. During the rotary mode, the
entire drill string is rotated from the surface, negating the effect of this bend and causing the
bit to drill on a straight course. During the sliding mode, drill string rotation is stopped and
a mud motor (which converts hydraulic energy from the drilling fluids being pumped through the
drill string into rotational energy at the bit) allows the bit to drill in the planned direction by
orienting its angled housing, gradually guiding the wellbore through an arc.
Baker Hughes was a pioneer and is a leader in the development and use of automated rotary
steerable technology. In rotary steerable environments, the entire drill string is turned from the
surface to supply energy to the bit. Unlike conventional systems, our AutoTrak® rotary steerable
system changes the trajectory of the well using three pads that push against the wellbore from a
non-rotating sleeve and is controlled by a downhole guidance system.
Our AutoTrak® Xtreme® system combines conventional mud motor technology with rotary steerable
technology to provide directional control and improved rate of penetration.
Measurement-While-Drilling. Directional drilling systems need real-time measurements of the
location and orientation of the bottom-hole assembly to operate effectively. MWD systems are
downhole tools that provide this directional information, which is necessary to adjust the drilling
process and guide the wellbore to a specific target. The AutoTrak® rotary steerable system has
these MWD systems built in, allowing the tool to automatically alter its course based on a planned
trajectory.
Logging-While-Drilling. LWD is a variation of MWD in which the LWD tool gathers information
on the petrophysical properties of the formation through which the wellbore is being drilled. Many
LWD measurements are the same as those taken via wireline; however, taking measurements in
real-time before any damage has been sustained by the reservoir as a result of the drilling process
often allows for greater accuracy. Real-time measurements also enable geo-steering where
geological markers identified by LWD tools are used to guide the bit and assure placement of the
wellbore in the optimal location.
In both MWD and LWD systems, surface communication with the tool is achieved through mud-pulse
telemetry, which uses pulse signals (pressure changes in the drilling fluids traveling through the
drill string) to communicate the operating conditions and location of the bottom-hole assembly to
the surface. The information transmitted is used to maximize the efficiency of the drilling
process, update and refine the reservoir model and steer the well into the optimal location in the
reservoir.
We are also a provider of mud logging services, through which our engineers monitor the
interaction between the drilling fluid and the formation and perform laboratory analysis of
drilling fluids and examinations of the drill cuttings to detect the presence of hydrocarbons and
identify the different geological layers penetrated by the drill bit.
The main drivers of customer purchasing decisions in these areas are the value added by
technology and the reliability and durability of the tools used in these operations. Specific
opportunities for competitive differentiation include:
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the sophistication and accuracy of measurements, |
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the efficiency of the drilling process (measured in cost per foot drilled), rate of
penetration, and reduction of non-productive time, |
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the reliability of equipment, |
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the optimal placement of the wellbore in the reservoir, and |
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the quality of the wellbore. |
Key business drivers for directional drilling, MWD and LWD include the number of drilling rigs
operating, the total footage drilled, the mix of conventional and rotary steerable systems used,
technological sophistication of and type of wells being drilled (vertical, deviated, horizontal or
extended reach), as well as the current and expected future price of both oil and natural gas. Our
primary competitors in drilling and evaluation services include Halliburton, Schlumberger and
Weatherford International Ltd. (Weatherford).
Wireline Formation Evaluation and Completion and Production Services
We are a leading provider of wireline formation evaluation and completion and production
services for oil and natural gas wells.
Wireline Formation Evaluation. Wireline formation evaluation involves measuring and analyzing
specific physical properties of the rock (petrophysical properties) in the immediate vicinity of a
wellbore to determine an oil or natural gas reservoirs boundaries, volume of hydrocarbons and
ability to produce fluids to the surface. Electronic sensor instrumentation is run through the
wellbore to measure porosity and density (how much open space there is in the rock), permeability
(how well connected the spaces in the rock are) and resistivity (whether there is oil, natural gas
or water in the spaces). Imaging tools are run through the wellbore to record a picture of the
formation along the wells length. Acoustic logs measure rock properties and help correlate
wireline data with previous seismic surveys. Magnetic resonance measurements characterize the
volume and type of fluids in the formation as well as provide a direct measure of permeability. At
the surface, measurements are recorded digitally and can be displayed on a continuous graph, or
well log, which shows how each parameter varies along the length of the wellbore. Wireline
formation evaluation tools can also be used to record formation pressures and take samples of
formation fluids to be further evaluated on the surface.
Wireline formation evaluation instrumentation can be run in the well in several ways and at
different times over the life of the well. The two most common methods of data collection are
wireline logging and LWD. Wireline logging is conducted by pulling or pushing instruments through
the wellbore after it is drilled, while LWD instruments are attached to the drill string and take
measurements while the well is being drilled. Wireline logging measurements can be made before the
wells protective steel casing is set (open hole logging) or after casing has been set (cased hole
logging). We also offer geophysical data interpretation services which help the operator interpret
the petrophysical properties measured by the logging instruments and make inferences about the
formation, presence and quantity of hydrocarbons. This information is used to determine the next
steps in drilling and completing the well.
Wireline Completion and Production Services. Wireline completion and production services
include using wireline instruments to evaluate well integrity, perform mechanical intervention and
perform cement evaluations. Wireline instruments can also be run in producing wells to perform
production logging. We also provide perforating services, which involve puncturing a wells steel
casing and cement sheath with explosive charges. This creates a fracture in the formation and
provides a path for hydrocarbons in the formation to enter the wellbore and be produced.
Formation evaluation services allow oil and natural gas companies to define, manage and reduce
their exploration and production risk. As such, the main driver of customer purchasing decisions
is the value added by formation evaluation and wireline completion and production services.
Specific opportunities for competitive differentiation include:
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the efficiency of data acquisition, |
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the sophistication and accuracy of measurements, |
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the ability to interpret the information gathered to quantify the hydrocarbons producible
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the efficiency of providing wireline completion and production services at the wellsite,
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the ability to differentiate services that can run exclusively or more efficiently on
wireline from services that run on drill pipe. |
Key business drivers for formation evaluation and wireline completion and perforating services
include the number of drilling and workover rigs operating, as well as the current and expected
future price of both oil and natural gas. Our primary competitors include Schlumberger,
Halliburton and Weatherford.
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Reservoir Technology and Consulting
Our reservoir technology and consulting group provides a broad range of services that assist
our customers in the evaluation, drilling, completion and production of oil and gas reservoirs.
Services include well planning, drilling optimization, formation evaluation and imaging, well
placement, sand control completions and stimulation and fracturing operations. We also provide
consulting services to assist customers with operations management, exploration and field
development and reservoir management.
COMPLETION AND PRODUCTION SEGMENT
Our Completion and Production segment provides products and services used in the completion
and production phase of oil and natural gas wells. This includes a wide variety of product lines
which support wellbore construction and completion. This segment also provides specialty chemicals
for the oilfield and refining markets, pipeline inspection and treatment services and the design,
manufacture and repair of artificial lift systems; permanent monitoring and chemical injection
systems; and integrated operations and project management services.
Wellbore Construction and Completion
Baker Hughes is a world leader in wellbore construction, cased-hole completions, sand control
and wellbore intervention solutions. The economic success of a well largely depends on how the
well is completed. A successful completion ensures and optimizes the efficient and safe production
of oil and natural gas to the surface. Our completion systems are matched to the formation and
reservoir for optimum production and can employ a variety of products and services.
Wellbore Construction. Wellbore completion products and services include liner hangers,
multilateral completion systems and expandable metal technology.
Liner hangers suspend a section of steel casing (also called a liner) inside the bottom of the
previous section of casing. The liner hangers expandable slips grip the inside of the casing and
support the weight of the liner below.
Multilateral completion systems enable two or more zones to be produced from a single well,
using multiple horizontal branches.
Expandable metal technology involves the permanent downhole expansion of a variety of tubular
products used in drilling, completion and well remediation applications.
Cased-Hole Completions. Cased-hole completions products and services include packers, flow
control equipment, subsurface safety valves and intelligent completions.
Packers seal the annular space between the steel production tubing and the casing. These
tools control the flow of fluids in the well and protect the casing above and below from reservoir
pressures and corrosive formation fluids.
Flow control equipment controls and adjusts the flow of downhole fluids. A common flow
control device is a sliding sleeve, which can be opened or closed to allow or limit production from
a particular portion of a reservoir. Flow control can be accomplished from the surface via
wireline or downhole via hydraulic or electric motor-based automated systems.
Subsurface safety valves shut off all flow of fluids to the surface in the event of an
emergency, thus saving the well and preventing pollution of the environment. These valves are
required in substantially all offshore wells.
Intelligent Completions® use real-time, remotely operated downhole systems to control the flow
of hydrocarbons from one or more zones.
Sand Control. Sand control equipment includes gravel pack tools, sand screens and fracturing
fluids. Sand control systems and pumping services are used in loosely consolidated formations to
prevent the production of formation sand with the hydrocarbons.
Wellbore Intervention. Wellbore intervention products and services are designed to protect
producing assets. Intervention operations troubleshoot drilling problems and improve, maintain or
restore economical production from already-producing wells. Products for wellbore intervention
range from service tools and inflatable products to conventional and through-tubing fishing
systems, casing exits, wellbore cleaning and temporary abandonment.
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Service tools function as surface-activated, downhole sealing and anchoring devices to isolate
a portion of the wellbore during repair or stimulation operations. Service tool applications range
from treating and cleaning to testing components from the wellhead to the perforations. Service
tools also refer to tools and systems that are used for temporary or permanent well abandonment.
Inflatable packers expand to set in pipe that is much larger than the outside diameter of the
packer itself, so it can run through a restriction in the well and then set in the larger diameter
below. Inflatable packers also can be set in open hole, whereas conventional tools only can be
set inside casing. Through-tubing inflatables enable remedial operations in producing wells.
Significant cost savings result from lower rig requirements and the ability to intervene in the
well without having to remove the completion.
Fishing tools and services are used to locate, dislodge and retrieve damaged or stuck pipe,
tools or other objects from inside the wellbore, often thousands of feet below the surface.
Wellbore cleaning systems remove post-drilling debris to help ensure trouble-free well
testing, completion and optimum production for the life of the well.
Casing exit systems are used to sidetrack new wells from existing ones, to provide a
cost-effective method of tapping previously unreachable reserves.
The main drivers of customer purchasing decisions in wellbore construction, cased-hole
completions, sand control and wellbore intervention are superior wellsite service execution and
value-adding technologies that improve production rates, protect the reservoir from damage and
reduce cost. Specific opportunities for competitive differentiation include:
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engineering and manufacturing superior-quality products and providing solutions with a
proven ability to reduce well construction costs, |
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enhancing production and ultimate recovery, |
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minimizing risks, and |
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providing reliable performance over the life of the well, particularly in harsh
environments and for critical wells. |
Key business drivers for wellbore construction and completion services include the number of
drilling and workover rigs operating, the relative complexity of the wells drilled and completed,
as well as the current and expected future price of both oil and natural gas. Our primary
competitors in wellbore construction, cased-hole completions and sand control include Halliburton,
Schlumberger and Weatherford. Our primary competitors in wellbore intervention include Weatherford
and Smith.
Specialty Chemicals
We are a leading provider of specialty chemicals to the oil and gas industry. We also supply
specialty chemicals to a number of industries including refining, pipeline transportation,
petrochemical, agricultural and iron and steel manufacturing and provide polymer-based products to
a broad range of industrial and consumer markets. Through our Pipeline Management Group, we offer
a variety of products and services for the pipeline transportation industry.
Oilfield Chemicals. We provide oilfield chemical programs for drilling, well stimulation,
production, pipeline transportation and maintenance programs. Our products provide measurable
increases in productivity, decreases in operating and maintenance costs and solutions to
environmental problems. Examples of specialty oilfield chemical programs include emulsion breakers
and chemicals which inhibit the formation of paraffin, scale, hydrates and other well performance
issues or problems.
Hydrate
inhibitors - Natural gas hydrates are solid ice-like crystals that form in production
flowlines and tubing and cause shutdowns and the need for system maintenance. Subsea wells and
flowlines, particularly in deepwater environments, are especially susceptible to hydrates.
Paraffin
inhibitors - The liquid hydrocarbons produced from many oil and natural gas
reservoirs become unstable soon after leaving the formation. Changing conditions, including
decreases in temperature and pressure, can cause certain hydrocarbons in the produced fluids to
crystallize and deposit on the walls of the wells tubing, flow lines and surface equipment. These
deposits are commonly referred to as paraffin. We offer solvents that remove the deposits, as well
as inhibitors that prevent new deposits from forming.
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Scale
inhibitors - Unlike paraffin deposits that originate from organic material in the
produced hydrocarbons, scale deposits come from mineral-based contaminants in water that are
produced from the formation as the water undergoes changes in temperature or pressure. Similar to
paraffin, scale deposits can clog the production system. Treatments prevent and remove deposits in
production systems.
Corrosion
inhibitors - Another problem caused by water mixed with downhole hydrocarbons is
corrosion of the wells tubulars and other production equipment. Corrosion can also be caused by
dissolved hydrogen sulfide (H2S) gas, which reacts with the iron in tubulars, valves
and other equipment, potentially causing failures and leaks. Additionally, the reaction creates
iron sulfide, which can impair treating systems and cause blockages. We offer a variety of
corrosion inhibitors and H2S scavengers.
Emulsion
breakers - Water and oil typically do not mix, but water present in the reservoir and
co-produced with oil can often become emulsified, or mixed, causing problems for oil and natural
gas producers. We also offer emulsion breakers that allow the water to be separated from the oil.
Refining, Industrial and Other Specialty Chemicals. For the refining industry, we offer
various process and water treatment programs, as well as finished fuel additives. Examples include
programs to remove salt from crude oil and to control corrosion in processing equipment and
environmentally friendly cleaners that decontaminate refinery equipment and petrochemical vessels
at a lower cost than other methods. We also provide chemical technology solutions to other
industrial markets throughout the world, including petrochemicals, fuel additives, plastics,
imaging, adhesives, steel and crop protection.
Pipeline Management. Baker Hughes offers a variety of products and services for the pipeline
transportation industry. We offer custom turnkey cleaning programs that improve efficiency by
combining chemical treatments with brush and scraper tools that are pumped through the pipeline.
Efficiency can also be improved by adding polymer-based drag reduction agents to reduce the slowing
effects of friction between the pipeline walls and the fluids within, thus increasing throughput
and pipeline capacity. Additional services allow pipelines to operate more safely. These include
inspection and internal corrosion assessment technologies, which physically confirm the structural
integrity of the pipeline. In addition, our flow-modeling capabilities can identify high-risk
segments of a pipeline to ensure proper mitigation programs are in place.
The main driver of customer purchasing decisions in specialty chemicals is superior
application of technology and service delivery. Specific opportunities for competitive
differentiation include:
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higher levels of production or throughput, |
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lower maintenance costs and frequency, |
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lower treatment costs and treatment intervals, and |
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successful resolution of environmental issues. |
Key business drivers for the sale of specialty chemicals and chemical treatment programs
include oil and natural gas production levels, the number of producing wells, total liquids
production, and the current and expected future price of both oil and natural gas. Our primary
competitors for specialty chemicals include Champion Technologies, Inc., Nalco Holding Company and
Smith.
Artificial Lift
We are a leading manufacturer and supplier of artificial lift systems including electrical
submersible pump systems (ESPs) and progressing cavity pump systems (PCPs).
Electrical Submersible Pump Systems. ESPs lift large quantities of oil or oil and water from
wells that do not flow under their own pressure. These artificial lift systems consist of a
centrifugal pump and electric motor installed in the wellbore, armored electric cabling to provide
power to the downhole motor and a variable speed controller at the surface. Baker Hughes designs,
manufactures, markets and installs all the components of ESPs and also offers modeling software to
size ESPs and simulate operating performance. ESPs may be used in both onshore and offshore wells.
The range of appropriate application of ESPs is expanding as technology and reliability
enhancements have improved ESPs performance in harsher environments and marginal reservoirs.
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Progressing Cavity Pump Systems. PCPs are a form of artificial lift comprised of a downhole
progressing cavity pump powered by either a downhole electric motor or a rod turned by a motor on
the surface. PCPs are preferred when the fluid to be lifted is viscous or when the volume is
significantly less than could be economically lifted with ESPs.
The main drivers of a customer purchasing decision in an artificial lift include the depth of
the well, the volume of the fluid, the physical and chemical properties of the fluid as well as the
capital and operating cost over the run life of the system. Specific opportunities for competitive
differentiation include:
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the ability to lift fluids of differing physical properties and chemical compositions, |
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system reliability and run life, |
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the ability of the system to optimize production, |
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operating efficiency, and |
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service delivery. |
Key business drivers for artificial lift systems include oil production levels, as well as the
current and expected future price of oil, the volume of water produced in mature basins and gas
dewatering in coal bed methane and other gas wells. Our primary competitors in the ESP market
include Schlumberger and John Wood Group PLC. In the PCP market, our competitors include
Weatherford, Robbins & Myers, Inc. and Kudu Industries, Inc.
Permanent Monitoring and Chemical Injection Systems
Permanent Monitoring Systems. Permanent downhole gauges are used in oil and gas wells to
measure temperature, pressure, flow and other parameters in order to monitor well production as
well as to confirm the integrity of the completion and production equipment in the well. We are a
leading provider of electronic gauges including the engineering, application and field services
necessary to complete an installation of a permanent monitoring system. In addition, we provide
chemical injection line installation and services for treating wells for corrosion, paraffin, scale
and other well performance problems. We also provide fiber optic based permanent downhole gauge
technology for measuring pressure, temperature and distributed temperature. The benefits of fiber
optic sensing include reliability, high temperature properties and the ability to obtain
distributed readings.
Chemical Automation Systems. Chemical automation systems remotely monitor chemical tank
levels that are resident in producing field locations for well treatment or production stimulation
as well as continuously monitor and control chemicals being injected in individual wells. By using
these systems, a producer can ensure proper chemical injection through real-time monitoring and can
also remotely modify the injection parameters to ensure optimized production.
The main drivers of customer purchasing decisions for both permanent monitoring and chemical
automation include application engineering expertise, ability to integrate a complete system,
product reliability, functionality and local field support. Specific opportunities for competitive
differentiation include:
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the ability to provide application engineering and economic return analysis, |
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product innovation, |
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gauge measurement accuracy, |
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product life and performance, and |
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installation and service capabilities. |
Key business drivers for permanent monitoring and chemical injection systems include the level
of oil and gas prices, total daily oil and gas production and capital spending for critical wells
(offshore, subsea, high production onshore and remotely located onshore). Our primary competitors
include Schlumberger, Halliburton and Weatherford.
9
Integrated Operations and Project Management
We are a provider of integrated operations, and we also manage projects on behalf of certain
customers around the world.
Integrated Operations and Project Management. Integrated operations is the process of
coordinating the delivery of multiple product lines and services to a specific customer or project
under a single contract or agreement. Project management encompasses the coordination and delivery
of multiple product lines as well as the provision and coordination of third-party products and
services in addition to those which we provide. Under a project management contract, we may be
asked to assume responsibility for certain risks related to a project. These assumed risks may
include the performance of our products and services, performance of products and services of
third-party providers, or completion of the project in accordance with specified technical
parameters or in a specified timeframe.
MARKETING, COMPETITION AND ECONOMIC CONDITIONS
We market our products and services on a product line basis primarily through our own sales
organizations, although certain of our products and services are marketed through independent
distributors, commercial agents, licensees or sales representatives. Over the past several years,
we have significantly reduced the number of commercial agents that we use to conduct our business.
In the markets in which we formerly utilized commercial agents, we have established our own
marketing operations and are continuing to build direct relationships with our customers. We
ordinarily provide technical and advisory services to assist in our customers use of our products
and services. Stock points and service centers for our products and services are located in areas
of drilling and production activity throughout the world.
Our products and services are sold in highly competitive markets, and revenues and earnings
can be affected by changes in competitive prices, fluctuations in the level of drilling, workover
and completion activity in major markets, general economic conditions, foreign currency exchange
fluctuations and governmental regulations. We compete with the oil and natural gas industrys
largest diversified oilfield services providers, as well as many small companies. We believe that
the principal competitive factors in our industries are product and service quality, availability
and reliability, health, safety and environmental standards, technical proficiency and price.
Further information is set forth in Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations and Note 13 of the Notes to Consolidated Financial
Statements in Item 8 herein.
INTERNATIONAL OPERATIONS
We operate in over 90 countries around the world and our corporate headquarters is in Houston,
Texas. We have significant manufacturing operations in various countries, including, but not
limited to, the United States (Texas, Oklahoma and Louisiana), the United Kingdom (Scotland and
Northern Ireland), Germany (Celle), South America (Venezuela and Argentina) and the United Arab
Emirates (Dubai). As of December 31, 2008, we had approximately 39,800 employees, of which
approximately 57% work outside the United States.
The business operations of our two segments are organized around four primary geographic
regions: North America; Latin America; Europe, Africa, Russia and the Caspian; and Middle East,
Asia Pacific. Through this structure, we have placed our management close to our customers,
facilitating stronger customer relationships and allowing us to react more quickly to local market
conditions and needs.
Our operations are subject to the risks inherent in doing business in multiple countries with
various laws and differing political environments. These risks include the risks identified in
Item 1A. Risk Factors. Although it is impossible to predict the likelihood of such occurrences
or their effect on us, we routinely evaluate these risks and take appropriate actions to mitigate
the risks where possible. However, there can be no assurance that an occurrence of any one or more
of these events would not have a material adverse effect on our operations.
Further information is set forth in Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
10
RESEARCH AND DEVELOPMENT; PATENTS
We are engaged in research and development activities directed primarily toward the
improvement of existing products and services, the design of specialized products to meet specific
customer needs and the development of new products, processes and services. For information
regarding the amounts of research and development expense in each of the three years in the period
ended December 31, 2008, see Note 1 of the Notes to Consolidated Financial Statements in Item 8
herein.
We have followed a policy of seeking patent and trademark protection both inside and outside
the United States for products and methods that appear to have commercial significance. We believe
our patents and trademarks to be adequate for the conduct of our business, and aggressively pursue
protection of our patents against patent infringement worldwide. Although patent and trademark
protection is important to our business and future prospects, we consider the reliability and
quality of our products and the technical skills of our personnel to be more important. No single
patent or trademark is considered to be critical to our business.
SEASONALITY
Our operations can be affected by seasonal weather patterns and natural phenomena, which can
temporarily affect the delivery and performance of our products and services, as well as customers
budgetary cycles for capital expenditures. The widespread geographic locations of our operations
and the timing of seasonal events serve to reduce the impact of individual events. Examples of
seasonal events which can impact our business include:
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the severity and duration of the winter in North America can have a significant impact on
gas storage levels and drilling activity for natural gas, |
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the timing and duration of the spring thaw in Canada directly affects activity levels due
to road restrictions, |
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hurricanes can disrupt coastal and offshore operations, |
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severe weather during the winter months normally results in reduced activity levels in
the North Sea and Russia, and |
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large export orders which tend to be sold in the second half of a calendar year. |
RAW MATERIALS
We purchase various raw materials and component parts for use in manufacturing our products.
The principal materials we purchase are steel alloys (including chromium and nickel), titanium,
beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, printed circuit boards
and other electronic components and hydrocarbon-based chemical feed stocks. These materials are
generally available from multiple sources and may be subject to price volatility. We have not
experienced significant shortages of these materials and normally do not carry inventories of such
materials in excess of those reasonably required to meet our production schedules. We do not
expect significant interruptions in supply, but there can be no assurance that there will be no
price or supply issues over the long term.
EMPLOYEES
On December 31, 2008, we had approximately 39,800 employees, as compared with approximately
35,800 employees on December 31, 2007. Approximately 3,200 of these employees are represented
under collective bargaining agreements or similar-type labor arrangements, of which the majority
are outside the U.S. Based upon the geographic diversification of these employees, we believe any
risk of loss from employee strikes or other collective actions would not be material to the conduct
of our operations taken as a whole.
11
EXECUTIVE OFFICERS
The following table shows, as of February 26, 2009, the name of each of our executive
officers, together with his age and all offices presently held.
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Name |
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Age |
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Chad C. Deaton
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56 |
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Chairman of the Board, President and Chief
Executive Officer of the Company since
February 2008. Chairman of the Board and
Chief Executive Officer from 2004 to 2008.
President and Chief Executive Officer of
Hanover Compressor Company from 2002 to
2004. Senior Advisor to Schlumberger
Oilfield Services from 1999 to 2001.
Executive Vice President of Schlumberger
from 1998 to 1999. Employed by the Company
in 2004. |
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Peter A. Ragauss
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51 |
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Senior Vice President and Chief Financial
Officer of the Company since 2006. Segment
Controller of Refining and Marketing for BP
plc from 2003 to 2006. Mr. Ragauss joined
BP plc in 1998 as Assistant to the Group
Chief Executive until 2000 when he became
Chief Executive Officer of Air BP. Vice
President of Finance and Portfolio
Management for Amoco Energy International
immediately prior to its merger with BP in
1998. Vice President of Finance for El
Paso Energy International from 1996 to 1998
and Vice President of Corporate Development
for Tenneco Energy in 1996. Employed by
the Company in 2006. |
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Alan R. Crain
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57 |
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Senior Vice President and General Counsel
of the Company since 2007. Vice President
and General Counsel from 2000 to 2007.
Executive Vice President, General Counsel
and Secretary of Crown, Cork & Seal
Company, Inc. from 1999 to 2000. Vice
President and General Counsel from 1996 to
1999, and Assistant General Counsel from
1988 to 1996, of Union Texas Petroleum
Holdings, Inc. Employed by the Company in
2000. |
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David H. Barr
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59 |
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Group President of Completion and
Production since 2007 and Vice President of
the Company from 1997 to 1998 and since
2000 until his retirement effective April 30, 2009. Group President of Drilling and
Evaluation from 2005 to 2007. President of
Baker Atlas from 2000 to 2005. Vice
President, Supply Chain Management, of
Cooper Cameron from 1999 to 2000. Mr. Barr
also held the following positions with the
Company: Vice President, Business Process
Development, from 1997 to 1998 and the
following positions with Hughes Tool
Company/Hughes Christensen: Vice
President, Production and Technology, from
1994 to 1997; Vice President, Diamond
Products, from 1993 to 1994; Vice
President, Eastern Hemisphere Operations,
from 1990 to 1993 and Vice President, North
American Operations, from 1988 to 1990.
Employed by the Company in 1972. |
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Martin S. Craighead
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49 |
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Senior Vice President and Chief
Operating Officer effective April 30, 2009. Group President of Drilling and Evaluation
since 2007 and Vice President of the
Company since 2005 until April 30, 2009. President of INTEQ
from 2005 to 2007. President of Baker
Atlas from February 2005 to August 2005.
Vice President of Worldwide Operations for
Baker Atlas from 2003 to 2005 and Vice
President, Marketing and Business
Development for Baker Atlas from 2001 to
2003; Region Manager for Baker Atlas in
Latin America and Asia and Region Manager
for E&P Solutions from 1995 to 2001.
Employed by the Company in 1986. |
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Russell J. Cancilla
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57 |
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Vice President, HS&E and Security of the
Company since 2009. Chief Security Officer
from June 2006 to January 2009. Vice
President and Security Officer of Innovene
from 2005 to 2006; Vice President,
Resources & Capabilities for HSSE for BP
from 2003 to 2005 and Vice President, Real
Estate and Management Services for BP from
1998 to 2003. Employed by the Company in
2006. |
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Didier Charreton
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45 |
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Vice President, Human Resources of the
Company since 2007. Group Human Resources
Director of Coats Plc, a global company
engaged in the sewing thread and
needlecrafts industry, from 2002 to 2007.
Business Development of ID Applications for
Gemplus S. A., a global company in the
Smart Card industry, from 2000 to 2001.
Various human resources positions at
Schlumberger from 1989 to 2000. Employed
by the Company in 2007. |
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Christopher P. Beaver |
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51 |
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Vice President of the Company and President
of Baker Oil Tools since 2005. Vice
President of Finance for Baker Petrolite
from 2002 to 2005; Director of Finance and
Controller at INTEQ from |
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Name |
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Age |
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1999 to 2002;
Controller at Hughes Christensen from 1994
to 1999. Various accounting and finance
positions at Hughes Christensen in the
Eastern Hemisphere from 1985 to 1994.
Employed by the Company in 1985. |
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Paul S. Butero
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52 |
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Vice President of the Company since 2005
and President of INTEQ since 2007.
President of Baker Atlas from 2006 to 2007.
President of Hughes Christensen from 2005
to 2006. Vice President, Marketing, of
Hughes Christensen from 2001 to 2005 and as
Region Manager for various Hughes
Christensen areas (both in the United
States and the Eastern Hemisphere) from
1989 to 2001. Employed by the Company in
1981. |
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Stephen K. Ellison
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50 |
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Vice President of the Company and President
of Baker Atlas since 2007. Vice President,
Middle East, Asia Pacific Region for Baker
Atlas from 2005 to 2007; Asia Pacific
Region Manager, Baker Atlas from 2001 to
2005 and Asia Pacific Region Operations
Manager, Baker Atlas from 2000 to 2001.
Employed by the Company in 1979. |
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Alan J. Keifer
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54 |
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Vice President and Controller of the
Company since 1999. Western Hemisphere
Controller of Baker Oil Tools from 1997 to
1999 and Director of Corporate Audit for
the Company from 1990 to 1996. Employed by
the Company in 1990. |
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Jay G. Martin
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57 |
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Vice President, Chief Compliance Officer
and Senior Deputy General Counsel of the
Company since 2004. Shareholder at
Winstead Sechrest & Minick P.C. from 2001
to 2004. Partner, Phelps Dunbar from 2000
to 2001 and Partner, Andrews & Kurth from
1996 to 2000. Employed by the Company in
2004. |
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Derek Mathieson
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38 |
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Vice President and Chief Technology and
Marketing Officer of the Company since
December 2008. Chief Executive Officer of
WellDynamics, Inc. from May 2007 to
November 2008. Vice President Business
Development, Technology and Marketing of
WellDynamics, Inc. from April 2006 to May
2007; Technology Director and Chief
Technology Officer from January 2004 to
April 2006; Research and Development
Manager from August 2002 to January 2004
and Reliability Assurance Engineer from
April 2001 to August 2002 of WellDynamics,
Inc. Well Engineer, Shell U.K. Exploration
and Production 1997 to 2001. Employed by
the Company in 2008. |
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Nelson Ney
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45 |
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Vice President of the Company and President
of Centrilift since 2007. Operations Vice
President, Europe, Africa, Russia and the
Caspian Region for Hughes Christensen from
2006 to 2007; Operations Vice President,
Centrilift Latin America Region from 2005
to 2006; General Manager, Centrilift Latin
America operations from 2004 to 2005 and
Regional Manager, Hughes Christensen Latin
America operations from 2001 to 2004.
Employed by the Company in 1990. |
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John A. ODonnell
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60 |
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Vice President of the Company since 1998
and President of Baker Petrolite
Corporation since 2005. President of Baker
Hughes Drilling Fluids from 2004 to 2005.
Vice President, Business Process
Development of the Company from 1998 to
2002; Vice President, Manufacturing, of
Baker Oil Tools from 1990 to 1998 and Plant
Manager of Hughes Tool Company from 1988 to
1990. Employed by the Company in 1975. |
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Gary G. Rich
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50 |
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Vice President of the Company and President
of Hughes Christensen since 2006. Vice
President Marketing, Drilling and
Evaluation for INTEQ from 2005 to 2006.
Region Manager for INTEQ from 2001 to 2005;
Director of Marketing for Hughes
Christensen from 1998 to 2001 and served in
various marketing and finance positions for
the Company from 1987 to 1998. Employed by
the Company in 1987. |
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Clifton N.B. Triplett
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50 |
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Vice President and Chief Information
Officer of the Company since September
2008. 2007 to 2008 Corporate Vice
President, Motorola Global Services and
Corporate Vice President and Chief
Information Officer of Motorolas Network
and Enterprise Group from 2006 to 2007.
Employed by General Motors from 1997 to
2006 as Global Information Systems Officer
for Computing and Telecommunications
Services from 2003 to 2006 and Global
Manufacturing and Quality Information
Systems Officer from 1997 to 2003.
Employed by the Company in 2008. |
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Name |
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Age |
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Richard L. Williams
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53 |
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Vice President of the Company and President
of Baker Hughes Drilling Fluids since 2005.
Vice President, Eastern Hemisphere
Operations, Baker Oil Tools from March 2005
to May 2005. Worldwide Operations Vice
President, INTEQ from 2004 to 2005; Vice
President Eastern Hemisphere, INTEQ from
2003 to 2004 and Vice President Western
Hemisphere, INTEQ from 2001 to 2003.
Employed by the Company in 1975. |
There are no family relationships among our executive officers.
ENVIRONMENTAL MATTERS
We are committed to the health and safety of people, protection of the environment and
compliance with laws, regulations and our policies. Our past and present operations include
activities that are subject to domestic (including U.S. federal, state and local) and international
regulations with regard to air and water quality and other environmental matters. We believe we
are in substantial compliance with these regulations. Regulation in this area continues to evolve,
and changes in standards of enforcement of existing regulations, as well as the enactment and
enforcement of new legislation, may require us and our customers to modify, supplement or replace
equipment or facilities or to change or discontinue present methods of operation.
We are involved in voluntary remediation projects at some of our present and former
manufacturing locations or other facilities, the majority of which relate to properties obtained in
acquisitions or to sites no longer actively used in operations. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order.
Estimated remediation costs are accrued using currently available facts, existing environmental
permits, technology and presently enacted laws and regulations. For sites where we are primarily
responsible for the remediation, our cost estimates are developed based on internal evaluations and
are not discounted. We record accruals when it is probable that we will be obligated to pay
amounts for environmental site evaluation, remediation or related activities, and such amounts can
be reasonably estimated. If the obligation can only be estimated within a range, we accrue the
minimum amount in the range. In general, we seek to accrue costs for the most likely scenario,
where known. Accruals are recorded even if significant uncertainties exist over the ultimate cost
of the remediation. Ongoing environmental compliance costs, such as obtaining environmental
permits, installation of pollution control equipment and waste disposal, are expensed as incurred.
The Comprehensive Environmental Response, Compensation and Liability Act (known as Superfund
or CERCLA) imposes liability for the release of a hazardous substance into the environment.
Superfund liability is imposed without regard to fault, even if the waste disposal was in
compliance with laws and regulations. The United States Environmental Protection Agency (the
EPA) and appropriate state agencies supervise investigative and cleanup activities at Superfund
sites.
We have been identified as a potentially responsible party (PRP) in remedial activities
related to various Superfund sites, and we accrue our share of the estimated remediation costs of
the site based on the ratio of the estimated volume of waste we contributed to the site to the
total volume of waste disposed at the site. PRPs in Superfund actions have joint and several
liability for all costs of remediation. Accordingly, a PRP may be required to pay more than its
proportional share of such costs. For some projects, it is not possible at this time to quantify
our ultimate exposure because the projects are either in the investigative or early remediation
stage, or allocation information is not yet available. However, based upon current information, we
do not believe that probable or reasonably possible expenditures in connection with the sites are
likely to have a material adverse effect on our consolidated financial statements because we have
recorded adequate reserves to cover the estimate we presently believe will be our ultimate
liability in the matter. Further, other PRPs involved in the sites have substantial assets and may
reasonably be expected to pay their share of the cost of remediation, and, in some circumstances,
we have insurance coverage or contractual indemnities from third parties to cover a portion of or
the ultimate liability.
During the year ended December 31, 2008, we spent $39 million to comply with domestic and
international standards regulating the discharge of materials into the environment or otherwise
relating to the protection of the environment (collectively, Environmental Regulations). This
cost includes the total spent on remediation projects at current or former sites, Superfund
projects and environmental compliance activities, exclusive of capital expenditures. In 2009, we
expect to spend approximately $41 million to comply with Environmental Regulations. During the
year ended December 31, 2008, we incurred $8 million in capital expenditures for environmental
control equipment, and we estimate we will incur approximately $18 million during 2009. Based upon
current information, we believe that our compliance with Environmental Regulations will not have a
material adverse effect upon our capital expenditures, earnings or competitive position because we
have either established adequate reserves or our cost for that compliance is not expected to be
material to our consolidated financial statements. Our total accrual for environmental remediation
is $17 million and $17 million, which includes accruals of $6 million and $5 million for the
various Superfund sites, at December 31, 2008 and 2007, respectively.
14
We are subject to various other governmental proceedings and regulations, including foreign
regulations, relating to environmental matters, but we do not believe that any of these matters is
likely to have a material adverse effect on our consolidated financial statements. We continue to
focus on reducing future environmental liabilities by maintaining appropriate company standards and
improving our assurance programs. See Note 15 of the Notes to Consolidated Financial Statements in
Item 8 herein for further discussion of environmental matters.
ITEM 1A. RISK FACTORS
An investment in our common stock involves various risks. When considering an investment in
our Company, one should consider carefully all of the risk factors described below, as well as
other information included and incorporated by reference in this report. There may be additional
risks, uncertainties and matters not listed below, that we are unaware of, or that we currently
consider immaterial. Any of these could adversely affect our business, financial condition,
results of operations and cash flows and, thus, the value of an investment in our Company.
Risk Factors Related to the Worldwide Oil and Natural Gas Industry
Our business is focused on providing products and services to the worldwide oil and natural
gas industry; therefore, our risk factors include those factors that impact, either positively or
negatively, the markets for oil and natural gas. Expenditures by our customers
for exploration, development and production of oil and natural gas are based on their
expectations of future hydrocarbon demand, the risks associated with developing the reserves, their
ability to finance exploration for and development of reserves, and the future value of the
reserves. Their evaluation of the future value is based, in part, on their expectations for global
demand, global supply, excess production capacity, inventory levels, and other factors that
influence oil and natural gas prices. The key risk factors currently influencing the worldwide oil
and natural gas markets are discussed below.
Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect
our operating results. The continuing weakness or further deterioration of the global economy or
credit market could reduce our customers spending levels and reduce our revenues and operating
results.
Demand for oil and natural gas, as well as the demand for our services, is highly correlated
with global economic growth, and in particular by the economic growth of countries such as the
U.S., India, and China, as well as developing Asia and the Middle East who are either significant
users of oil and natural gas or whose economies are experiencing the most rapid economic growth
compared to the global average. The slowdown in global economic growth and recession in the
developed economies has resulted in reduced demand for oil and natural gas, increased spare
productive capacity and lower energy prices. The continuing weakness or further deterioration of
the global economy or credit market could reduce our customers spending levels and reduce our
revenues and operating results. Expectations for reduced hydrocarbon demand have adversely
impacted demand for our services. Incremental weakness in global economic activity, particularly
in China, India, the Middle East and developing Asia will reduce demand for oil and natural gas and
result in lower oil and natural gas prices. Incremental strength in global economic activity in
such areas will create more demand for oil and natural gas and support higher oil and natural gas
prices. In addition, demand for oil and natural gas could be impacted by environmental regulation
or carbon taxes targeting reduction of greenhouse gas emissions or the cost for carbon capture and
sequestration related regulations.
Volatility of oil and natural gas prices can adversely affect demand for our products and services.
Volatility in oil and natural gas prices can also impact our customers activity levels and
spending for our products and services. Current energy prices are important contributors to cash
flow for our customers and their ability to fund exploration and development activities.
Expectations about future prices and price volatility are important for determining future spending
levels.
Lower oil and gas prices generally lead to decreased spending by our customers. While higher
oil and natural gas prices generally lead to increased spending by our customers, sustained high
energy prices can be an impediment to economic growth, and can therefore negatively impact spending
by our customers. Our customers also take into account the volatility of energy prices and other
risk factors by requiring higher returns for individual projects if there is higher perceived risk.
Any of these factors could affect the demand for oil and natural gas and could have a material
adverse effect on our results of operations.
15
Many of our customers activity levels and spending for our products and services and ability to
pay amounts owed us may be impacted by deterioration in the credit markets.
Access to capital is dependent on our customers ability to access the funds necessary to
develop economically attractive projects based upon their expectations of future energy prices,
required investments and resulting returns. Limited access to external sources of funding has
caused many customers to reduce their capital spending plans to levels supported by
internally-generated cash flow. In addition, the combination of a reduction of cash flow resulting
from declines in commodity prices, a reduction in borrowing bases under reserve-based credit
facilities and the lack of availability of debt or equity financing may impact the ability of our
customers to pay amounts owed to us.
Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect
our operating results.
Productive capacity for oil and natural gas is dependent on our customers decisions to
develop and produce oil and natural gas reserves. The ability to produce oil and natural gas can
be affected by the number and productivity of new wells drilled and completed, as well as the rate
of production and resulting depletion of existing wells. Advanced technologies, such as horizontal
drilling, improve total recovery but also result in a more rapid production decline.
Access to prospects is also important to our customers. Access to prospects may be limited
because host governments do not allow access to the reserves or because another oil and natural gas
exploration company owns the rights to develop the prospect. Government regulations and the costs
incurred by oil and natural gas exploration companies to conform to and comply with government
regulations, may also limit the quantity of oil and natural gas that may be economically produced.
Supply can also be impacted by the degree to which individual Organization of Petroleum
Exporting Countries (OPEC) nations and other large oil and natural gas producing countries,
including, but not limited to, Norway and Russia, are willing and able to control production and
exports of oil, to decrease or increase supply and to support their targeted oil price while
meeting their market share objectives. Any of these factors could affect the supply of oil and
natural gas and could have a material adverse effect on our results of operations.
Changes in spare productive capacity or inventory levels can be indicative of future customer
spending to explore for and develop oil and natural gas which in turn influences the demand for our
products and services.
Spare productive capacity and oil and natural gas storage inventory levels are an indicator of
the relative balance between supply and demand. High or increasing storage or inventories
generally indicate that supply is exceeding demand and that energy prices are likely to soften.
Low or decreasing storage or inventories are an indicator that demand is growing faster than supply
and that energy prices are likely to rise. Measures of maximum productive capacity compared to
demand (spare productive capacity) are also an important factor influencing energy prices and
spending by oil and natural gas exploration companies. When spare productive capacity is low
compared to demand, energy prices tend to be higher and more volatile reflecting the increased
vulnerability of the entire system to disruption.
Seasonal and adverse weather conditions adversely affect demand for our services and operations.
Weather can also have a significant impact on demand as consumption of energy is seasonal, and
any variation from normal weather patterns, cooler or warmer summers and winters, can have a
significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of
Mexico, may interrupt or curtail our operations, or our customers operations, cause supply
disruptions and result in a loss of revenue and damage to our equipment and facilities, which may
or may not be insured. Extreme winter conditions in Canada, Russia or the North Sea may interrupt
or curtail our operations, or our customers operations, in those areas and result in a loss of
revenue.
Risk Factors Related to Our Business
Our expectations regarding our business are affected by the following risk factors and the
timing of any of these risk factors:
We operate in a highly competitive environment, which may adversely affect our ability to succeed.
We operate in a highly competitive environment for marketing oilfield services and securing
equipment and trained personnel. Our ability to continually provide competitive products and
services can impact our ability to defend, maintain or increase prices for our products and
services, maintain market share and negotiate acceptable contract terms with our customers. In
order to be competitive, we must provide new technologies and reliable products and services that
perform as expected and that create value for
16
our customers. Our ability to defend, maintain or increase prices for our products and
services is in part dependent on the industrys capacity relative to customer demand, and on our
ability to differentiate the value delivered by our products and services from our competitors
products and services. In addition, our ability to negotiate acceptable contract terms and
conditions with our customers, especially state-owned national oil companies, our ability to manage
warranty claims and our ability to effectively manage our commercial agents can also impact our
results of operations.
Managing development of competitive technology and new product introductions on a forecasted
schedule and at forecasted costs can impact our financial results. Development of competing
technology that accelerates the obsolescence of any of our products or services can have a
detrimental impact on our financial results and can result in the potential impairment of
long-lived assets.
We may be disadvantaged competitively and financially by a significant movement of exploration
and production operations to areas of the world in which we are not currently active.
The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel,
particularly in periods of rapid growth, could adversely affect our ability to execute our
operations on a timely basis.
Our manufacturing operations are dependent on having sufficient raw materials, component parts
and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while
minimizing inventories. Our ability to effectively manage our manufacturing operations and meet
these goals can have an impact on our business, including our ability to meet our manufacturing
plans and revenue goals, control costs and avoid shortages of raw materials and component parts.
Raw materials and components of particular concern include steel alloys (including chromium and
nickel), titanium, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds,
electronic components and hydrocarbon-based chemical feed stocks. Our ability to repair or replace
equipment damaged or lost in the well can also impact our ability to service our customers. A lack
of manufacturing capacity could result in increased backlog, which may limit our ability to respond
to short lead time orders.
People are a key resource to developing, manufacturing and delivering our products and
services to our customers around the world. Our ability to manage the recruiting, training and
retention of the highly skilled workforce required by our plans and to manage the associated costs
could impact our business. A well-trained, motivated work force has a positive impact on our
ability to attract and retain business. Periods of rapid growth present a challenge to us and our
industry to recruit, train and retain our employees while managing the impact of wage inflation and
potential lack of available qualified labor in the markets where we operate. Likewise, in the
current condition of the economy and our markets, we may have to adjust our workforce to control
costs and yet not lose our skilled and diverse workforce. Labor-related actions, including
strikes, slowdowns and facility occupations can also have a negative impact on our business.
Our business is subject to geopolitical and terrorism risks.
Geopolitical risks and terrorist activity continue to grow in several key countries where we
do business. Geopolitical risks could lead to, among other things, a loss of our investment in the
country and an inability to collect our accounts receivable. Terrorism risks could lead to a loss
of our investment in the country, as well as a disruption in business activities. Key oil
producing countries in which we do business include Angola, Brazil, Canada, China, Norway, Russia,
Saudi Arabia, U.K., U.S. and Venezuela.
Maintaining or developing the capacity (infrastructure, people and equipment) to provide our
products and services in future periods can have a detrimental impact on near-term profitability.
Maintaining infrastructure, a highly-skilled technical workforce, and high technology
equipment for future demands can have a detrimental impact on near-term profitability. Conversely,
failure to maintain adequate infrastructure, a highly-skilled technical workforce, and high
technology equipment can result in lost sales during periods of unanticipated demand.
17
The terms and the impact of the settlement with the Department of Justice (DOJ) and SEC may
negatively impact our ongoing operations.
Under the settlements in connection with the previously disclosed compliance investigations by
the DOJ and SEC, we are subject to ongoing review and regulation of our business operations,
including the review of our operations and compliance program by an independent monitor appointed
to assess our Foreign Corrupt Practices Act (FCPA) policies and procedures. The activities of
the independent monitor will have a cost to us and may cause a change in our processes and
operations, the outcome of which we are unable to predict. In addition, the settlements may impact
our operations or result in legal actions against us in the countries that are the subject of the
settlements. Also, the collateral impact of settlement in the United States and other countries
outside the United States where we do business that may claim jurisdiction over any of the matters
related to the DOJ and SEC settlements could be material. These settlements could also result in
third-party claims against us, which may include claims for special, indirect, derivative or
consequential damages.
Our failure to comply with the terms of our agreements with the DOJ and SEC would have a negative
impact on our ongoing operations.
Under the settlements with the DOJ and SEC, we are subject to a two-year deferred prosecution
agreement and enjoined by the federal district court against any further violations of the FCPA.
Accordingly, the settlements reached with the DOJ and SEC could be substantially nullified and we
could be subject to severe sanctions and civil and criminal prosecution as well as fines and
penalties in the event of a subsequent violation by us or any of our employees or our failure to
meet all of the conditions contained in the settlements. The impact of the settlements on our
ongoing operations could include limits on revenue growth and increases in operating costs. Our
ability to comply with the terms of the settlements is dependent on the success of our ongoing
compliance program, including our ability to continue to manage our agents and business partners
and supervise, train and retain competent employees and the efforts of our employees to comply with
applicable law and the Baker Hughes Business Code of Conduct.
Compliance with and changes in laws or adverse positions taken by taxing authorities could be
costly and could affect operating results.
We have operations in the U.S. and in over 90 countries that can be impacted by expected and
unexpected changes in the legal and business environments in which we operate. Our ability to
manage our compliance costs will impact our ability to meet our earnings goals. Compliance related
issues could also limit our ability to do business in certain countries. Changes that could impact
the legal environment include new legislation, new regulations, new policies, investigations and
legal proceedings and new interpretations of existing legal rules and regulations, in particular,
changes in export control laws or exchange control laws, additional restrictions on doing business
in countries subject to sanctions, and changes in laws in countries where we operate or intend to
operate. Changes that impact the business environment include changes in accounting standards,
changes in environmental laws, changes in tax laws or tax rates, the resolution of tax assessments
or audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards
and tax credits. In addition, we may periodically restructure our legal entity organization. If
taxing authorities were to disagree with our tax positions in connection with any such
restructurings, our effective tax rate could be materially impacted.
These changes could have a significant financial impact on our future operations and the way
we conduct, or if we conduct, business in the affected countries.
Uninsured claims and litigation could adversely impact our operating results.
We could be impacted by the outcome of pending litigation as well as unexpected litigation or
proceedings. We have insurance coverage against operating hazards, including product liability
claims and personal injury claims related to our products, to the extent deemed prudent by our
management and to the extent insurance is available, however, no assurance can be given that the
nature and amount of that insurance will be sufficient to fully indemnify us against liabilities
arising out of pending and future claims and litigation. This insurance has deductibles or
self-insured retentions and contains certain coverage exclusions. The insurance does not cover
damages from breach of contract by us or based on alleged fraud or deceptive trade practices.
Whenever possible, we obtain agreements from customers that limit our liability. Insurance and
customer agreements do not provide complete protection against losses and risks, and our results of
operations could be adversely affected by unexpected claims not covered by insurance.
18
Compliance with and rulings and litigation in connection with environmental regulations may
adversely affect our business and operating results.
Our business is impacted by unexpected outcomes or material changes in environmental
liability. Our expectations regarding our compliance with environmental regulations and our
expenditures to comply with environmental regulations, including (without limitation) our capital
expenditures for environmental control equipment, are only our forecasts regarding these matters.
These forecasts may be substantially different from actual results, which may be affected by the
following factors: changes in environmental regulations; a material change in our allocation or
other unexpected, adverse outcomes with respect to sites where we have been named as a PRP,
including (without limitation) Superfund sites; the discovery of new sites of which we are not
aware and where additional expenditures may be required to comply with environmental regulations;
an unexpected discharge of hazardous materials.
Control of oil and gas reserves by state-owned oil companies may impact the demand for our services
and create additional risks in our operations.
Much of the worlds oil and gas reserves are controlled by state-owned oil companies.
State-owned oil companies may require their contractors to meet local content requirements or other
local standards, such as joint ventures, that could be difficult or undesirable for the Company to
meet. The failure to meet the local content requirements and other local standards may adversely
impact the Companys operations in those countries.
In addition, many state-owned oil companies may require integrated contracts or turn-key
contracts that could require the Company to provide services outside its core business. Providing
services on an integrated or turnkey basis generally requires the Company to assume additional
risks.
Changes in economic conditions and currency fluctuations may impact our operating results.
Fluctuations in foreign currencies relative to the U.S. Dollar can impact our revenue and our
costs of doing business. Most of our products and services are sold through contracts denominated
in U.S. Dollars or local currency indexed to U.S. Dollars. Some revenue and some local expenses
and some of our manufacturing costs are incurred in local currencies and therefore changes in the
exchange rates between the U.S. Dollar and foreign currencies, particularly the British Pound
Sterling, Euro, Canadian Dollar, Norwegian Krone, Venezuelan Bolivar, Russian Ruble, Australian
Dollar and Brazilian Real, can increase or decrease our revenue and expenses reported in U.S.
Dollars and may impact our results of operations.
The condition of the capital markets and equity markets in general can affect the price of our
common stock and our ability to obtain financing, if necessary. If the Companys credit rating is
downgraded, this would increase borrowing costs under our revolving credit agreements and
commercial paper program, as well as the cost of renewing or obtaining, or make it more difficult
to renew or obtain or issue, new debt financing.
Our ability to forecast the size of and changes in the worldwide oil and natural gas industry
and our ability to forecast our customers activity levels and demand for our products and services
impacts our management of our manufacturing and distribution activities, our staffing levels and
our cash and financing requirements. Unanticipated changes in our customers requirements can
impact our costs, creating temporary shortages or surpluses of equipment and people and demands for
cash or financing.
Changes in market conditions may impact any stock repurchases.
To the extent the Company engages in stock repurchases, such activity is subject to market
conditions, such as the trading prices for our stock, as well as the terms of any stock purchase
plans intended to comply with Rule 10b5-1 or Rule 10b-18 of the Exchange Act. Management, in its
discretion, may engage in or discontinue stock repurchases at any time.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We are headquartered in Houston, Texas and operate 49 principal manufacturing plants, ranging
in size from approximately 7,500 to 300,000 square feet of manufacturing space. The total
aggregate area of the plants is approximately 3.5 million square feet, of which approximately 2.3
million square feet (64%) are located in North America, 0.3 million square feet (8%) are located in
Latin America, 0.8 million square feet (24%) are located in Europe, and a minimal amount of space
is located in the Middle East, Asia
19
Pacific region. Our principal manufacturing plants are located in: (i) North America -
Houston, Texas; Broken Arrow, Claremore and Tulsa, Oklahoma;
Lafayette, Louisiana, Calgary, Canada;
(ii) Latin America - Maracaibo, Venezuela; Mendoza, Argentina; (iii) Europe Africa, Russia and the
Caspian - Aberdeen and East Kilbride, Scotland; Celle, Germany; Belfast, Northern Ireland; and (vi)
Middle East, Asia Pacific - Dubai, United Arab Emirates.
We own or lease numerous service centers, shops and sales and administrative offices
throughout the geographic regions in which we operate. We also have a significant investment in
service vehicles, rental tools and manufacturing and other equipment. We believe that our
manufacturing facilities are well maintained and suitable for their intended purposes. The table
below shows our principal manufacturing plants by segment and geographic region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Africa, Russia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and the |
|
Middle East, |
|
|
Segment |
|
North America |
|
Latin America |
|
Caspian |
|
Asia Pacific |
|
Total |
|
Completion and Production |
|
|
18 |
|
|
|
3 |
|
|
|
7 |
|
|
|
2 |
|
|
|
30 |
|
Drilling and Evaluation |
|
|
13 |
|
|
|
1 |
|
|
|
4 |
|
|
|
1 |
|
|
|
19 |
|
ITEM 3. LEGAL PROCEEDINGS
The information with respect to Item 3. Legal Proceedings is contained in Note 15 of the Notes
to Consolidated Financial Statements in Item 8 herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
20
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
Our common stock, $1.00 par value per share, is principally traded on the New York Stock
Exchange. Our common stock is also traded on the SWX Swiss Exchange. As of February 20, 2009,
there were approximately 240,400 stockholders and approximately 14,800 stockholders of record.
For information regarding quarterly high and low sales prices on the New York Stock Exchange
for our common stock during the two years ended December 31, 2008, and information regarding
dividends declared on our common stock during the two years ended December 31, 2008, see Note 17 of
the Notes to Consolidated Financial Statements in Item 8 herein.
The following table contains information about our purchases of equity securities during the
fourth quarter of 2008.
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
Maximum |
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
|
|
|
Number (or |
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
|
|
|
Total |
|
Approximate |
|
|
|
|
|
|
|
|
|
|
Purchased |
|
|
|
|
|
Number of |
|
Dollar Value) of |
|
|
|
|
|
|
|
|
|
|
as Part of a |
|
|
|
|
|
Shares |
|
Shares that May |
|
|
Total Number |
|
Average |
|
Publicly |
|
Average |
|
Purchased |
|
Yet Be |
|
|
of Shares |
|
Price Paid |
|
Announced |
|
Price Paid |
|
in the |
|
Purchased Under |
Period |
|
Purchased(1) |
|
Per Share(1) |
|
Program(2) |
|
Per Share(3) |
|
Aggregate |
|
the Program(4) |
|
October 1-31, 2008 |
|
|
7,290 |
|
|
$ |
31.43 |
|
|
|
380,000 |
|
|
$ |
42.67 |
|
|
|
387,290 |
|
|
$ |
|
|
November 1-30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 1-31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7,290 |
|
|
$ |
31.43 |
|
|
|
380,000 |
|
|
$ |
42.67 |
|
|
|
387,290 |
|
|
$ |
1,197,127,803 |
|
|
|
|
|
(1) |
|
Represents shares purchased from employees to pay the option exercise price related
to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations
in connection with the vesting of restricted stock awards and restricted stock units. |
|
(2) |
|
Repurchases were made under a Stock Purchase Plan with an agent that complied with
the requirements of Rule 10b5-1 of the Exchange Act (the Plan). On August 25, 2008, we
entered into a Plan that ran from September 2, 2008 through October 23, 2008. Under the Plan,
the agent repurchased a number of shares of our common stock determined under the terms of the
Plan each trading day based on the trading price of the stock on that day. Shares were
repurchased under the Plan by the agent at the prevailing market prices, in open market
transactions which complied with Rule 10b-18 of the Exchange Act. |
|
(3) |
|
Average price paid includes commissions. |
|
(4) |
|
During the fourth quarter of 2008, we repurchased 380,000 shares of our common
stock at an average price of $42.67 per share, for a total of $16 million with authorization
remaining to repurchase up to a total of $1,197 million of our common stock as of the end of
2008. |
21
Corporate Performance Graph
The following graph compares the yearly change in our cumulative total stockholder return on
our common stock (assuming reinvestment of dividends into common stock at the date of payment) with
the cumulative total return on the published Standard & Poors 500 Stock Index and the cumulative
total return on Standard & Poors 500 Oil and Gas Equipment and Services Index over the preceding
five-year period.
Comparison of Five-Year Cumulative Total Return *
Baker Hughes Incorporated; S&P 500 Index and S&P 500 Oil and Gas Equipment and Services Index
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2004 |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
|
|
Baker Hughes |
|
$ |
100.00 |
|
|
$ |
134.28 |
|
|
$ |
193.07 |
|
|
$ |
238.78 |
|
|
$ |
261.11 |
|
|
$ |
104.28 |
|
S&P 500 Index |
|
|
100.00 |
|
|
|
110.88 |
|
|
|
116.32 |
|
|
|
134.69 |
|
|
|
142.09 |
|
|
|
89.52 |
|
S&P 500 Oil and Gas Equipment and Services Index |
|
|
100.00 |
|
|
|
131.86 |
|
|
|
195.90 |
|
|
|
226.35 |
|
|
|
334.76 |
|
|
|
136.66 |
|
|
|
|
* |
|
Total return assumes reinvestment of dividends on a quarterly basis. |
The comparison of total return on investment (change in year-end stock price plus reinvested
dividends) assumes that $100 was invested on December 31, 2003 in Baker Hughes common stock, the
S&P 500 Index and the S&P 500 Oil and Gas Equipment and Services Index.
The Corporate Performance Graph and related information shall not be deemed soliciting
material or to be filed with the SEC, nor shall such information be incorporated by reference
into any future filing under the Securities Act or the Exchange Act, except to the extent that
Baker Hughes specifically incorporates it by reference into such filing.
22
ITEM 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial
Statements and Supplementary Data, both contained herein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
(In millions, except per share amounts) |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
Revenues |
|
$ |
11,864 |
|
|
$ |
10,428 |
|
|
$ |
9,027 |
|
|
$ |
7,185 |
|
|
$ |
6,080 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues |
|
|
7,954 |
|
|
|
6,845 |
|
|
|
5,876 |
|
|
|
5,024 |
|
|
|
4,428 |
|
Research and engineering |
|
|
426 |
|
|
|
372 |
|
|
|
339 |
|
|
|
300 |
|
|
|
272 |
|
Marketing, general and administrative |
|
|
1,046 |
|
|
|
933 |
|
|
|
878 |
|
|
|
628 |
|
|
|
563 |
|
Litigation settlement |
|
|
62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
9,488 |
|
|
|
8,150 |
|
|
|
7,093 |
|
|
|
5,952 |
|
|
|
5,263 |
|
|
Operating income |
|
|
2,376 |
|
|
|
2,278 |
|
|
|
1,934 |
|
|
|
1,233 |
|
|
|
817 |
|
Equity in income of affiliates |
|
|
2 |
|
|
|
1 |
|
|
|
60 |
|
|
|
100 |
|
|
|
36 |
|
Gain on sale of product line |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
1,744 |
|
|
|
|
|
|
|
|
|
Impairment loss on investments |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(89 |
) |
|
|
(66 |
) |
|
|
(69 |
) |
|
|
(72 |
) |
|
|
(84 |
) |
Interest and dividend income |
|
|
27 |
|
|
|
44 |
|
|
|
68 |
|
|
|
18 |
|
|
|
7 |
|
|
Income from continuing operations before income
taxes |
|
|
2,319 |
|
|
|
2,257 |
|
|
|
3,737 |
|
|
|
1,279 |
|
|
|
776 |
|
Income taxes |
|
|
(684 |
) |
|
|
(743 |
) |
|
|
(1,338 |
) |
|
|
(405 |
) |
|
|
(250 |
) |
|
Income from continuing operations |
|
|
1,635 |
|
|
|
1,514 |
|
|
|
2,399 |
|
|
|
874 |
|
|
|
526 |
|
Income from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
5 |
|
|
|
3 |
|
|
Income before cumulative effect of accounting
change |
|
|
1,635 |
|
|
|
1,514 |
|
|
|
2,419 |
|
|
|
879 |
|
|
|
529 |
|
Cumulative effect of accounting change, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
Net income |
|
$ |
1,635 |
|
|
$ |
1,514 |
|
|
$ |
2,419 |
|
|
$ |
878 |
|
|
$ |
529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
5.32 |
|
|
$ |
4.76 |
|
|
$ |
7.26 |
|
|
$ |
2.58 |
|
|
$ |
1.57 |
|
Diluted |
|
|
5.30 |
|
|
|
4.73 |
|
|
|
7.21 |
|
|
|
2.56 |
|
|
|
1.57 |
|
Dividends |
|
|
0.56 |
|
|
|
0.52 |
|
|
|
0.52 |
|
|
|
0.48 |
|
|
|
0.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, cash equivalents and short-term investments |
|
$ |
1,955 |
|
|
$ |
1,054 |
|
|
$ |
1,104 |
|
|
$ |
774 |
|
|
$ |
319 |
|
Working capital |
|
|
4,634 |
|
|
|
3,837 |
|
|
|
3,346 |
|
|
|
2,479 |
|
|
|
1,738 |
|
Total assets |
|
|
11,861 |
|
|
|
9,857 |
|
|
|
8,706 |
|
|
|
7,807 |
|
|
|
6,821 |
|
Long-term debt |
|
|
1,775 |
|
|
|
1,069 |
|
|
|
1,074 |
|
|
|
1,078 |
|
|
|
1,086 |
|
Stockholders equity |
|
|
6,807 |
|
|
|
6,306 |
|
|
|
5,243 |
|
|
|
4,698 |
|
|
|
3,895 |
|
Notes To Selected Financial Data
(1) |
|
Litigation settlement. 2008 income from continuing operations includes a net charge of $62
million relating to the settlement of litigation with ReedHycalog. |
|
(2) |
|
Gain on sale of product line. 2008 income from continuing operations includes $28 million
for the gain on the sale of the Completion and Production segments Surface Safety Systems
(SSS) product line. |
|
(3) |
|
Impairment loss on investments. 2008 income from continuing operations includes a charge for
impairment loss on investments of $25 million relating to auction rate securities. |
|
(4) |
|
Equity in income of affiliates and gain on sale of interest in affiliate. On April 28, 2006,
we sold our 30% interest in WesternGeco, a seismic venture we formed with Schlumberger in
2000, and recorded a gain of $1,744 million on the sale. |
|
(5) |
|
Discontinued operations. The selected financial data includes reclassifications to reflect
Baker Supply Products Division, as discontinued operations. See Note 2 of the Notes to
Consolidated Financial Statements in Item 8 herein for additional information regarding
discontinued operations. |
|
(6) |
|
Cumulative effect of accounting change. In 2005, we adopted Financial Accounting Standards
Board (FASB) Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. |
23
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Managements Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
should be read in conjunction with the consolidated financial statements of Item 8. Financial
Statements and Supplementary Data contained herein.
EXECUTIVE SUMMARY
We are a major supplier of wellbore related products and technology services and systems and
provide products and services for drilling, formation evaluation, completion and production, and
reservoir technology and consulting to the worldwide oil and natural gas industry. We report our
results under two segments: the Drilling and Evaluation segment and the Completion and Production
segment, which are aligned by product line based upon the types of products and services provided
to our customers and upon the business characteristics of the product lines divisions during
business cycles. Collectively, we refer to the results of these two segments as Oilfield
Operations.
The business operations of our divisions are organized around four primary geographic regions:
North America; Latin America; Europe, Africa, Russia and the Caspian; and Middle East, Asia
Pacific. Each region has a council comprised of regional vice presidents from each division as
well as representatives from various functions such as human resources, legal including compliance,
marketing, finance and treasury, and health, safety and environmental. The regional vice
presidents report directly to each division president. Through this structure, we have placed our
management close to our customer, facilitating stronger customer relationships and allowing us to
react more quickly to local market conditions and needs.
The primary driver of our business is our customers capital and operating expenditures
dedicated to exploring, and drilling for, and developing and producing oil and natural gas. Our
business is cyclical and is dependent upon our customers expectations for future oil and natural
gas prices, future economic growth, hydrocarbon demand and estimates of future oil and natural gas
production.
2008 was a year of extreme volatility in oil and natural gas prices, and it marked the turning
point of a multi-year up-cycle in the oilfield service business and the worldwide economy. The
year began with oil prices trading near $100/Bbl and natural gas prices in the U.S. market trading
near $8/mmBtu. Tight supply conditions, lower than expected growth in non-OPEC production,
projections of strong demand growth, particularly in China, India and the Middle East, and weakness
in the U.S. Dollar drove oil prices to a record $145/Bbl in early July. Natural gas prices
continued to rise through the first half of the year in response to the increase in oil prices,
expectations for demand growth and lower imports of liquefied natural gas (LNG) compared to 2007.
In this environment, our customers, which include super-major and major integrated oil and
natural gas companies, independent oil and natural gas companies and state-owned national oil
companies (NOCs), continued to move forward with exploration and development projects. In the
U.S., the number of rigs drilling for natural gas in tight shale formations continued to increase,
providing strong demand for our Drilling and Evaluation product lines. In Canada, increased gas
prices and improved economics for gas producers resulted in strong activity following the spring
break-up. International activity, which is more oriented toward oil producing projects, also
continued to expand.
In the second half of 2008, the outlook for the worldwide economy deteriorated. Projections
for worldwide oil demand were revised downward and oil prices began to retreat from historic highs.
The decline in oil prices accelerated in the fourth quarter of 2008, hitting a low of $31/Bbl in
late December. Despite the decline in oil prices, international activity held through the balance
of the year. International activity is generally characterized by large, multi-year projects which
do not react materially to short-term changes in commodity prices.
In the U.S., the outlook for natural gas demand also weakened as concern grew about the
worldwide economy and the emerging probability that increasing production from the unconventional
shale plays would lead to an over-supplied gas market. Natural gas prices trended down from
mid-year highs to close the year under $6/mmBtu. The decrease in natural gas prices impacted
economics for some gas producers, placing pressure on rig activity. Compounding the impact of
lower gas prices was the sharp reduction in credit availability that occurred as financial
institutions reacted to events following the subprime crisis. Many independent operators in the
U.S. have relied upon external sources of funding to execute exploration and development plans.
The reduction in external funding sources has resulted in a significant number of companies
curtailing exploration budgets to a level which can be funded through internally-generated cash
flow. This credit crisis in not limited to customers in the U.S., and the impact has spread to
customers worldwide.
In
this challenging environment, we generated revenues of $11.86 billion in 2008, a 14%
increase compared with 2007, exceeding the 7% increase in the worldwide average rig count for 2008
compared with 2007. Our North American revenues increased 17% compared to a 6% increase in the
U.S. rig count and an 11% increase in the Canadian rig count. Our revenues outside of North
24
America increased 12% compared to 2007. In addition to the growth in our revenues from
increased activity, our revenues were impacted by changes in market share in certain product lines
and to a lesser extent pricing improvements. Net income for 2008 was $1.64 billion compared with
$1.51 billion in 2007. As of December 31, 2008, we had approximately 39,800 employees, up 4,000
employees from December 31, 2007. Approximately 57% of our employees work outside the United
States.
In early 2009,
the global economy continued to weaken. Many of our customers have announced
reductions in their planned 2009 spending, and we have seen continued decreases in drilling
activity, particularly in the U.S. land market. During the nine weeks
following the end of December 2008, the U.S. rig count declined 478 rigs or 28%. In January 2009, we began necessary actions to adjust our
operating cost base including a reduction in workforce. We will continue to monitor market
conditions and adjust our cost base as deemed necessary.
BUSINESS ENVIRONMENT
Our business environment and its corresponding operating results are significantly affected by
the level of energy industry spending for the exploration, development, and production of oil and
natural gas reserves. Spending by oil and natural gas exploration and production companies is
dependent upon their forecasts regarding the expected future supply and future demand for oil and
natural gas products and their estimates of risk-adjusted costs to find, develop, and produce
reserves. Changes in oil and natural gas exploration and production spending will normally result
in increased or decreased demand for our products and services, which will be reflected in the rig
count and other measures.
The credit crisis, declining oil prices, lower natural gas prices, and a weakening global
economic outlook are all impacting our business environment. Our customers typically fund their
activity through a combination of borrowed funds and internally-generated cash flow. The limited
availability of commercial credit is having a negative effect on both the general economy and the
ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices
and natural gas prices from 2008 mid-summer highs has also negatively impacted our customers
operational cash flow, further challenging their ability to continue to operate at past levels as
well as their future spending for our products and services. The economic slowdown is also
negatively impacting the incremental demand for hydrocarbon products especially in OECD
(Organization for Economic Cooperation and Development) countries.
Oil and Natural Gas Prices
Generally, changes in the current price and expected future price of oil or natural gas drive
customers expectations about their prospects from oil and natural gas sales and their expenditures
to explore for or produce oil and natural gas. Accordingly, changes in these expenditures will
normally result in increased or decreased demand for our products and services. Oil (Bloomberg
West Texas Intermediate (WTI) Cushing Crude Oil Spot Price) and natural gas (Bloomberg Henry Hub
Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing
prices during each of the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Oil prices ($/Bbl) |
|
$ |
99.92 |
|
|
$ |
72.23 |
|
|
$ |
66.09 |
|
Natural gas prices ($/mmBtu) |
|
|
8.89 |
|
|
|
6.96 |
|
|
|
6.73 |
|
Oil prices averaged a nominal historic high of $99.92/Bbl in 2008. The year 2008 began with
oil prices trading near $100/Bbl in early January. Oil prices continued to increase through the
first half of the year due to concerns about weak inventory levels, limited worldwide excess
productive capacity and concerns that demand growth would outpace production growth. The weakening
of the U.S. Dollar relative to other currencies also contributed to the increase in oil prices.
Oil prices peaked in early July at $145.29/Bbl. Oil prices declined throughout the fourth quarter of
2008 on expectations that the weakening worldwide economy would adversely impact demand. Oil
prices fell to a yearly low of $31.41/Bbl in late December.
Natural gas prices averaged $8.89/mmBtu for the year 2008. The year 2008 began with high
levels of natural gas in storage and natural gas prices in the $8/mmBtu range. Cold weather
provided price support through the first quarter of the year. Natural gas prices continued to
strengthen through the first half of the year, reflecting lower LNG imports relative to 2007 and
increasing oil prices. Natural gas prices reached a peak of over $13/mmBtu in early July. Through
the balance of the year, growth in natural gas production, building inventories and concerns of
weakening demand placed pressure on natural gas prices, which declined to a low of $5.37/mmBtu in
late December.
Rig Counts
We have been providing rig counts to the public since 1944. We gather all relevant data
through our field service personnel, who obtain the necessary data from routine visits to the
various rigs, customers, contractors or other outside sources. This data is then compiled and
distributed to various wire services and trade associations and is published on our website. Rig
counts are compiled
25
weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs.
Published international rig counts do not include rigs drilling in certain locations, such as
Russia, the Caspian and onshore China, because this information cannot be readily obtained.
Rigs in the U.S. are counted as active if, on the day the count is taken, the well being
drilled has been started but drilling has not been completed and the well is anticipated to be of
sufficient depth, which may change from time to time and may vary from region to region, to be a
potential consumer of our drill bits. Rigs in Canada are counted as active if data obtained by the
Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have
occurred during the week and we are able to verify this information. In most international areas,
rigs are counted as active if drilling operations have taken place for at least 15 days during the
month. In some active international areas where better data is available, a weekly or daily
average of active rigs is taken. In those international areas where there is poor availability of
data, the rig counts are estimated from third party data. The rig count does not include rigs that
are in transit from one location to another, are rigging up, are being used in non-drilling
activities, including production testing, completion and workover, or are not significant consumers
of drill bits.
Our rig counts are summarized in the table below as averages for each of the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
U.S. land and inland waters |
|
|
1,814 |
|
|
|
1,695 |
|
|
|
1,559 |
|
U.S. offshore |
|
|
65 |
|
|
|
73 |
|
|
|
90 |
|
Canada |
|
|
382 |
|
|
|
343 |
|
|
|
471 |
|
|
North America |
|
|
2,261 |
|
|
|
2,111 |
|
|
|
2,120 |
|
|
Latin America |
|
|
384 |
|
|
|
355 |
|
|
|
324 |
|
North Sea |
|
|
45 |
|
|
|
48 |
|
|
|
49 |
|
Other Europe |
|
|
53 |
|
|
|
29 |
|
|
|
28 |
|
Africa |
|
|
65 |
|
|
|
66 |
|
|
|
58 |
|
Middle East |
|
|
280 |
|
|
|
265 |
|
|
|
238 |
|
Asia Pacific |
|
|
252 |
|
|
|
241 |
|
|
|
228 |
|
|
Outside North America |
|
|
1,079 |
|
|
|
1,004 |
|
|
|
925 |
|
|
Worldwide |
|
|
3,340 |
|
|
|
3,115 |
|
|
|
3,045 |
|
|
RESULTS OF OPERATIONS
The discussions below relating to significant line items from our consolidated statements of
operations are based on available information and represent our analysis of significant changes or
events that impact the comparability of reported amounts. Where appropriate, we have identified
specific events and changes that affect comparability or trends and, where possible and practical,
have quantified the impact of such items. The discussions are based on our consolidated financial
results, as individual segments do not contribute disproportionately to our revenues, profitability
or cash requirements. In addition, the discussions below for revenues and cost of revenues are on
a combined basis as the business drivers for the individual components of product sales and service
and rentals are similar.
The table below details certain consolidated statement of operations data and their percentage
of revenues (dollar amounts in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
|
$ |
|
% |
|
$ |
|
% |
|
$ |
|
% |
|
Revenues |
|
$ |
11,864 |
|
|
|
100 |
% |
|
$ |
10,428 |
|
|
|
100.0 |
% |
|
$ |
9,027 |
|
|
|
100 |
% |
Cost of revenues |
|
|
7,954 |
|
|
|
67 |
% |
|
|
6,845 |
|
|
|
66 |
% |
|
|
5,876 |
|
|
|
65 |
% |
Research and engineering |
|
|
426 |
|
|
|
4 |
% |
|
|
372 |
|
|
|
4 |
% |
|
|
339 |
|
|
|
4 |
% |
Marketing, general and administrative |
|
|
1,046 |
|
|
|
9 |
% |
|
|
933 |
|
|
|
9 |
% |
|
|
878 |
|
|
|
10 |
% |
26
Revenues:
2008 Compared to 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
|
|
|
|
December 31, |
|
Increase |
|
|
|
|
2008 |
|
2007 |
|
(decrease) |
|
% Change |
|
Geographic Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
$ |
5,178 |
|
|
$ |
4,441 |
|
|
$ |
737 |
|
|
|
17 |
% |
Latin America |
|
|
1,127 |
|
|
|
903 |
|
|
|
224 |
|
|
|
25 |
% |
Europe, Africa, Russia and the Caspian |
|
|
3,386 |
|
|
|
3,076 |
|
|
|
310 |
|
|
|
10 |
% |
Middle East, Asia Pacific |
|
|
2,173 |
|
|
|
2,008 |
|
|
|
165 |
|
|
|
8 |
% |
|
Total revenues |
|
$ |
11,864 |
|
|
$ |
10,428 |
|
|
$ |
1,436 |
|
|
|
14 |
% |
|
Revenues for 2008 increased 14% compared to 2007 primarily due to increases in activity in
certain geographic areas, as evidenced by a 7% increase in the worldwide rig count, price
improvement and changes in market share in selected product lines and geographic areas. These
increases were partially offset by the impact of hurricanes in the Gulf of Mexico.
North America
Revenues in North America, which accounted for 44% of total revenues, increased 17% in 2008
compared to 2007, despite the unfavorable impact on our U.S. offshore revenues from
hurricane-related disruptions in 2008. The improvement in North America revenues was led by our
Completion and Production segment and directional drilling, as evidenced by a 7% increase in the
U.S. rig count for land and inland water drilling. The U.S. offshore rig count was down 11% due to
the continued migration of rigs out of the Gulf of Mexico to more attractive international markets
and weather-related disruptions. Canada revenues increased 12% compared to an 11% increase in the
rig count reflecting improved economics for Canadian natural gas producers.
Outside North America
Revenues outside North America, which accounted for 56% of total revenues, increased 12% in
2008 compared to 2007. This increase reflected the improvement in international drilling activity,
as evidenced by a 7% increase in the rig count outside North America, and market share gains in
certain geographic areas.
Latin America revenues increased 25% compared to an 8% increase in the rig count. The
improved revenue in Latin America was led by directional drilling systems in Brazil and Colombia;
completions and production systems in Mexico; and drill bits throughout the region.
Europe, Africa, Russia and the Caspian revenues increased 10%. The improved revenue in the
region was led by all product lines across both segments in Norway and Libya; and completion
systems as well as multiple product lines in the Drilling and Evaluation segment in both
Kazakhstan and Russia partially offset by lower drilling activity in the U.K.
Middle East, Asia Pacific revenues increased 8%. Middle East revenues increased 9% compared
to a 6% increase in the rig count. Asia Pacific revenues were up 7% compared to a 5% increase in
the rig count. The improvement in revenues from the region was led by our Completion and
Production segment in China and sales of various other product lines throughout the region
including Oman and United Arab Emirates.
2007 Compared to 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
|
|
|
|
December 31, |
|
Increase |
|
|
|
|
2007 |
|
2006 |
|
(decrease) |
|
% Change |
|
Geographic Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
$ |
4,441 |
|
|
$ |
4,076 |
|
|
$ |
365 |
|
|
|
9 |
% |
Latin America |
|
|
903 |
|
|
|
751 |
|
|
|
152 |
|
|
|
20 |
% |
Europe, Africa, Russia and the Caspian |
|
|
3,076 |
|
|
|
2,489 |
|
|
|
587 |
|
|
|
24 |
% |
Middle East, Asia Pacific |
|
|
2,008 |
|
|
|
1,711 |
|
|
|
297 |
|
|
|
17 |
% |
|
Total revenues |
|
$ |
10,428 |
|
|
$ |
9,027 |
|
|
$ |
1,401 |
|
|
|
16 |
% |
|
27
Revenues for 2007 increased 16% compared to 2006 primarily due to increases in activity in
certain geographic areas and, to a lesser extent, improvement in price and net changes in market
share.
North America
Revenues in North America, which accounted for 42% of total revenues, increased 9% as strength
in land-based activity for natural gas in the U.S. offset the impact of a 19% decrease in the
offshore rig count and a 27% decrease in the Canadian rig count. Canada revenues decreased 9%
compared to a 27% decrease in the rig count, reflecting lower average natural gas prices in 2007
compared to 2006, and more challenging economics for natural gas producers.
Outside North America
Revenues outside North America, which account for 58% of total revenues, increased 21% in 2007
compared to 2006. This increase reflected the improvement in international drilling activity, as
evidenced by a 9% increase in the rig count outside North America.
Latin America revenues increased 20% compared to a 10% increase in the rig count. The
increase was driven by higher activity and share in Brazil and activity increases in Colombia and
Mexico.
Europe, Africa, Russia and the Caspian revenues increased 24%. Revenues from Russia and the
Caspian were up 50%, and revenues from Europe were up 21% on a 1% increase in the rig count, driven
by increased activity in the U.K. and Norwegian sectors of the North Sea. Revenues in Africa were
up 14%, in line with the increase in the rig count.
Middle East, Asia Pacific revenues increased 17%. Middle East revenues increased 19% compared
to an 11% increase in the rig count, driven by our activities in Qatar, Egypt, and Saudi Arabia.
Asia Pacific revenues increased 16% compared to a 6% increase in the rig count. Growth in the Asia
Pacific region was led by Australia and Malaysia.
Cost of Revenues
Cost of revenues for 2008 increased 16% compared with 2007. Cost of revenues as a percentage
of revenues was 67% and 66% for 2008 and 2007, respectively. The increase in cost of revenues as a
percentage of consolidated revenues was primarily due to a change in the geographic and product mix
from the sale of our products and services and increasingly competitive conditions and pricing
pressures, particularly in North America. In addition, higher raw material costs and labor costs
contributed to the increase.
Cost of revenues for 2007 increased 17% compared with 2006. Cost of revenues as a percentage
of revenues was 66% and 65% for 2007 and 2006, respectively. The increase in cost of revenues as a
percentage of consolidated revenues was primarily due to a change in the geographic and product mix
from the sale of our products and services and increasingly competitive conditions and pricing
pressures, particularly in North America. In addition, higher raw material costs and labor costs
contributed to the increase. Effective January 1, 2007, we increased the depreciable lives of
certain assets of our Baker Atlas division resulting in a reduction to cost of services and rentals
for 2007 of approximately $23 million.
Research and Engineering
Research and engineering expenses increased 15% in 2008 compared with 2007 and 10% in 2007
compared with 2006. The increase in both years reflects our increase in research and development
expenses through our continued commitment in developing and commercializing new technologies as
well as an increase in engineering expenses as we continue to invest in our core product offerings.
Research and development costs increased 12% in 2008 compared with 2007 and 8% in 2007 compared
with 2006. During 2007, we opened the first phase of the Center for Technology and Innovation in
Houston, Texas. This facility focuses on research and development of completion and production
systems in harsh environments. The second phase was completed in 2008.
Marketing, General and Administrative
Marketing, general and administrative (MG&A) expenses increased 12% in 2008 compared with
2007 and increased 6% in 2007 compared with 2006. These increases correspond with increased
activity and resulted primarily from higher employee related costs including compensation, training
and benefits, higher marketing expenses as a result of increased activity and an increase in legal,
tax and other compliance related expenses. These increases were partially offset by foreign
exchange gains.
28
Litigation Settlement
In connection with the settlement of litigation with ReedHycalog, in June 2008, the Company
paid ReedHycalog $70 million in royalties for prior use of certain patented technologies, and
ReedHycalog paid the Company $8 million in royalties for the license of certain Company patented
technologies. The net pre-tax charge of $62 million for the settlement of this litigation is
reflected in the 2008 consolidated statement of operations. See Note 15. Commitment and
Contingencies Litigation in the Notes to Consolidated Financial Statements in Item 8 herein.
Gain on Sale of Product Line and Interest in Affiliate
In February 2008, we sold the assets associated with the Completion and Production segments
Surface Safety Systems (SSS) product line and received cash proceeds of $31 million. The SSS
assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We
recorded a pre-tax gain of $28 million ($18 million after-tax).
On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in
cash and recorded a pre-tax gain of $1,744 million ($1,035 million after-tax).
Impairment Loss on Investments
The Company has investments in auction rate securities (ARS) that represent interests in
three variable rate debt securities. These are credit linked notes and generally combine low risk
assets and credit default swaps (CDS) to create a security that pays interest from the assets
coupon payments and the periodic sale proceeds of the CDS. Since September 2007, we have been
unable to sell our ARS investments because of unsuccessful auctions. We estimated the fair value
of our ARS investments based on the underlying structure of each security and their collateral
values, including assessments of counterparty credit quality, default risk underlying the security,
expected cash flows, discount rates and overall capital market liquidity. Based on this analysis,
in December 2008 we recorded an other-than-temporary impairment loss of $25 million, which is
included in our consolidated statement of operations. As of December 31, 2008, we held ARS
investments totaling $11 million.
Interest Expense and Interest and Dividend Income
Interest expense increased $23 million in 2008 compared with 2007, due to the new long-term
debt issuances of $1.25 billion in October 2008 along with higher average debt levels throughout
2008. Interest expense decreased $3 million in 2007 compared with 2006 primarily due to slightly
lower average total debt levels.
Interest and dividend income decreased $17 million in 2008 compared with 2007, primarily due
to lower interest rates throughout 2008 on our short-term investment balances compared with 2007.
Interest and dividend income decreased $24 million in 2007 compared with 2006, primarily due to
lower average cash and short-term investment balances in 2007 as a result of our share repurchase
programs.
Income Taxes
Our effective tax rates in 2008 and 2007 are 29.5% and 32.9%, respectively, which are lower
than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international
operations offset by state income taxes. Our effective tax rate in 2006 was 35.8%, which was
higher than the U.S. statutory income tax rate of 35% due to taxes related to the sale of our
interest in the WesternGeco venture and state income taxes, offset by lower rates of tax on our
international operations. During 2006, we provided $708 million for taxes related to the sale of
our interest in WesternGeco, which included an estimate of taxes related to the future repatriation
of the non-U.S. proceeds.
Our tax filings for various periods are subject to audit by the tax authorities in most
jurisdictions where we conduct business. These audits may result in assessment of additional taxes
that are resolved with the authorities or through the courts. We believe these assessments may
occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have
received tax assessments from various taxing authorities and are currently at varying stages of
appeals and/or litigation regarding these matters. We believe we have substantial defenses to the
questions being raised and will pursue all legal remedies should an unfavorable outcome result.
However, resolution of these matters involves uncertainties and there are no assurances that the
outcomes will be favorable. We provide for uncertain tax positions pursuant to FIN 48, Accounting
for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.
29
OUTLOOK
Worldwide Oil and Natural Gas Industry Outlook
This section should be read in conjunction with the factors described in the Risk Factors
Related to the Worldwide Oil and Natural Gas Industry and the Risk Factors Related to Our
Business in Item 1A. Risk Factors and in the Forward-Looking Statements section in Item 7, both
contained herein. These factors could impact, either positively or negatively, our expectation
for: oil and natural gas demand; oil and natural gas prices; exploration and development spending
and drilling activity; and production spending.
The credit crisis, declining oil prices, lower natural gas prices, and a weakening global
economic outlook are all impacting our business environment. Our customers typically fund their
activity through a combination of borrowed funds and internally-generated cash flow. The limited
availability of commercial credit is having a negative effect on both the general economy and the
ability of our customers to continue to operate at pre-crisis levels. The decline in oil prices
and natural gas prices from 2008 mid-summer highs has also negatively impacted our customers
operational cash flow, further challenging their ability to continue to operate at past levels as
well as their future spending for our products and services. Last, the economic slowdown is also
negatively impacting the incremental demand for hydrocarbon products especially in OECD countries.
Our outlook for exploration and development spending is based upon our expectations for
customer spending in the markets in which we operate, and is driven primarily by our perception of
industry expectations for oil and natural gas prices and their likely impact on customer capital
and operating budgets as well as other factors that could impact the economic return oil and gas
companies expect for developing oil and gas reserves. Our forecasts are based on our analysis of
information provided by our customers as well as market research and analyst reports including the
Short Term Energy Outlook (STEO) published by the Energy Information Administration of the U.S.
Department of Energy (DOE), the Oil Market Report published by the International Energy Agency
(IEA) and the Monthly Oil Market Report published by the Organization for Petroleum Exporting
Countries (OPEC). Our outlook for economic growth is based on our analysis of information
published by a number of sources including the International Monetary Fund (IMF), OECD and the
World Bank.
As an oil service company, our revenue is dependent on spending by our customers to explore
for, develop and produce oil and natural gas. Exploration and development spending by our
customers is dependent on a number of factors including: their forecasts of future energy demand;
their expectations for future energy prices; their access to reserves to develop and produce oil
and gas; and their ability to fund their capital programs.
Our industry is cyclical, and past cycles have been driven primarily by alternating periods of
ample supply or shortage of oil and natural gas relative to demand. The current down cycle is
different in that the primary driver is the rapid deterioration of the global economy, which has
led to declining demand and forecasts for further reductions in future demand. The recent drop in
commodity prices, in conjunction with reduced access to the debt markets, has forced many oil and
gas companies to reduce their spending to levels supportable by their expected free cash flow.
In North America, the outlook for spending in 2009 is also dependent on the outlook for the
natural gas industry. Increased drilling activity and the application of horizontal drilling and
advanced fracturing and completion technologies in the unconventional gas fields has resulted in
gas production exceeding demand. Natural gas prices have fallen and are not expected to increase
until drilling is reduced to a level below the rate necessary to offset depletion, and supply and
demand come back into balance. The commodity cycle in North American natural gas is being
aggravated by the recession, low natural gas prices and reduced access to credit for many of our
customers.
The outlook for the global economy and the depth and duration of the recession remains
uncertain. We use third party forecasts, including forecasts by the IMF, World Bank and OECD, to
set its expectations for global economic growth. Through February 2009, each month has brought
incremental negative revisions to the forecasted economic level for 2009. The IEA, OPEC and the
Energy Information Administration (EIA) have also made significant negative revisions to their
forecasts of 2009 oil demand over the past 8 months.
Expectations for Oil Prices - As a result of the global economic recession, demand for oil is
expected to decrease in a range from 0.6 million to 1.2 million barrels per day in 2009 compared to
2008. Non-OPEC supply growth is expected to moderate in response to decreased spending and is now
expected to increase 0.1 million to 0.5 million barrels per day. Decreased demand and increased
non-OPEC production are expected to pressure OPEC to make significant cuts in its production levels
in an attempt to support oil prices. Inventories and spare productive capacity, which buffer oil
markets from supply disruptions, are expected to increase as the gap between increasing supply and
decreasing demand grows. In its February 2009 STEO report, the DOE forecasted oil prices to
average $43/Bbl in 2009. Oil prices are volatile. The DOE expects the balance of supply in 2010
to tighten somewhat allowing prices to
30
increase to an average of $55/Bbl for 2010. Variables that could significantly affect this
forecast include changes in the assumption for global economic growth and energy demand, changes or
delays in non-OPEC supply additions and OPEC quota discipline.
Expectations for North American Natural Gas Prices - The combination of rising natural gas
production and recession-driven decreases in natural gas demand are expected to drive gas prices
lower in 2009 compared to 2008. In its January 2009 STEO report, the DOE forecasted that U.S.
natural gas demand would decrease 1.0% in 2009 compared to 2008 assuming continued economic
weakness and that natural gas prices would average about $5/mmBtu in 2009, down from $8.89/mmBtu in
2008. North American gas-directed drilling activity is expected to decrease in the U.S. resulting
in fewer supply additions from new wells to offset production declines from existing wells. Gas
prices are expected to remain soft until the gap between supply and demand tightens as gas demand
growth exceeds gas supply growth for some period of time. The DOE forecasts gas prices to increase
modestly to $6/mmBtu in 2010. Prices remain volatile with the economy, weather-driven demand,
imports of Canadian gas, LNG imports and production from the lower 48 states gas fields playing
significant roles in determining both prices and price volatility. Variations in the supply demand
balance will be reflected in gas storage levels.
Industry Activity and Customer Spending - Our forecasts of activity and customer spending are
based upon our discussions with major customers, reviews of published industry reports, our outlook
for oil and natural gas prices described above, and our outlook for drilling activity, as measured
by the Baker Hughes rig count. We believe that our customers 2009 spending plans are based on
forecasts of oil and gas prices and energy demand similar to those stated above. In addition, each
companys 2009 spending plans also reflect company-specific drivers such as their ability to
finance their 2009 spending plans as well as their assessments of the uncertainty associated with
their forecasts. At current and expected oil and natural gas prices, some projects that were
planned in 2008 to begin in 2009 or 2010 may no longer be economically attractive. In light of
current economic conditions and current oil and gas prices, we believe that our customers, as a
group, are planning to decrease spending in 2009 as compared to 2008.
|
|
|
Outside North America – Both customer spending and drilling activity, primarily directed
at developing oil supplies, are expected to decrease approximately 10% to 15% in 2009
compared with 2008. Spending on producing oil and gas from developed fields is expected to
remain flat or decrease modestly in 2009 reflecting the stability in oil and gas production
levels. |
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|
|
North America – Both customer spending and drilling activity in North America, primarily
towards developing natural gas supplies, is expected to decrease approximately 25% to 30% in
2009 compared to 2008. Spending on producing oil and gas from developed fields is expected
to remain flat or decrease modestly in 2009 reflecting the stability in oil and gas
production levels. |
Our customers are likely to reduce their planned spending if oil prices were expected to trade
below $40/Bbl for an extended period of time. The risks to oil prices falling below $40/Bbl for a
significant period of time include: (1) any incremental weakness in the global economic outlook;
(2) significant unexpected increases in non-OPEC production; (3) any significant disruption to
worldwide demand; (4) reduced geo-political tensions; (5) poor OPEC quota discipline; or (6) other
factors that result in increased spare productive capacity or higher oil inventory levels or
decreased demand.
Company Outlook
This section should be read in conjunction with the factors described in the Risk Factors
Related to Our Business, Risk Factors Related to the Worldwide Oil and Natural Gas Industry and
Forward-Looking Statements sections contained herein. These factors could impact, either
positively or negatively, our expectation for oil and natural gas demand, oil and natural gas
prices and drilling activity.
North American revenue is expected to decline approximately 15% to 25% in 2009 compared to
2008 reflecting reduced customer spending and deterioration of pricing offset somewhat by modest
share gains. Decreases in revenue for our Drilling and Evaluation segment are expected to be
greater than the decline in revenue for our Completion and Production segment. In 2008, 2007 and
2006, North American revenues were 44%, 42%, and 44% of total revenues, respectively.
Outside of North America we expect revenues to decline approximately 5% to 15% in 2009
compared to 2008 with the most significant declines occurring in the Eastern Hemisphere. Share
gains and activity increases in Brazil and Latin America could result in an increase in Latin
America revenues in 2009 compared to 2008. Spending on large projects by NOCs are expected to
reflect established seasonality trends. In addition, customer spending could be affected by
weather-related reductions in the North Sea in the first and second quarters of 2009. In 2008,
2007 and 2006, revenues outside North America were 56%, 58% and 56% of total revenues,
respectively.
Profit is expected to decline in 2009 compared to 2008 as a result of lower activity levels
and deterioration of pricing offset only partially by cost reductions. Factors that could have a
significant positive impact on profitability include: less than expected price
31
deterioration for our products and services; lower than expected raw material and labor costs;
and/or higher than expected planned activity. Conversely, greater than expected price
deterioration, higher than expected raw material and labor costs and/or lower than expected
activity would have a negative impact on profitability. Our ability to limit price deterioration
is dependent on demand for our products and services, our competitors strategies for managing
capacity in a declining market, our competitors strategies for defending market share and price,
and our customers strategies for obtaining price concessions.
Our 2009 capital budget supports the continuation of the infrastructure expansion we began in
late 2006 and early 2007. In 2007, we opened new or expanded facilities in many regions and/or
countries including Latin America, the Middle East, and Russia. In addition in 2007, we opened the
first phase of our Center for Technology and Innovation in Houston, a research and engineering
facility to design advanced completion systems for high pressure, high temperature hostile
environments. The second phase was completed in 2008. Also in 2008, we opened our new campus in
Dubai which includes our Middle East and Asia Pacific region headquarters, a regional operations
center, and a training center which expands our Eastern Hemisphere training capabilities. Capital
expenditures are expected to be approximately $1.1 billion to $1.2 billion for 2009, including
approximately $350 million to $400 million that we expect to spend on infrastructure, primarily
outside of North America. A significant portion of our planned capital expenditures can be
adjusted to reflect changes in our expectations for future customer spending. We expect to manage
our capital expenditures to match market demand.
The execution of our 2009 business plan and the ability to meet our 2009 financial objectives
are dependent on a number of factors. Key factors include: activity and spending levels in each
of our markets; the relative strength of the oilfield services competition in each market and our
ability to limit price decreases and manage raw material and labor costs. Other factors include,
but are not limited to, our ability to: adjust our workforce to control costs while recruiting,
training and retaining the skilled and diverse workforce necessary to meet our future business
needs; continue to expand our business in areas that are expected to grow most rapidly when the
economy and energy market recover (such as NOCs), and in areas where we have market share
opportunities (such as the Middle East, Russia and the Caspian region and India); manage raw
material and component costs (especially steel alloys, copper, tungsten carbide, lead, nickel,
chemicals and electronic components); continue to make ongoing improvements in the productivity of
our manufacturing organization and manage our spending in the North American market.
Compliance
We do business in over 90 countries, including approximately one-half of the 40 countries
having the lowest scores, which indicates high levels of corruption, in Transparency
Internationals Corruption Perception Index survey for 2008. We devote significant resources to the
development, maintenance and enforcement of our Business Code of Conduct policy, our anti-bribery
compliance policies, our internal control processes and procedures and other compliance related
policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof,
from time to time we discover or receive information alleging potential violations of laws and
regulations, including the FCPA and our policies, processes and procedures. We conduct internal
investigations of these potential violations and take appropriate action depending upon the outcome
of the investigation.
We anticipate that the devotion of significant resources to compliance-related issues,
including the necessity for investigations, will continue to be an aspect of doing business in a
number of the countries in which oil and natural gas exploration, development and production take
place and in which we are requested to conduct operations. Compliance-related issues have limited
our ability to do business and/or have raised the cost of operating in these countries. In order
to provide products and services in some of these countries, we may in the future utilize ventures
with third parties, sell products to distributors or otherwise modify our business approach in
order to improve our ability to conduct our business in accordance with applicable laws and
regulations and our Business Code of Conduct.
Our Best-in-Class Global Ethics and Compliance Program (Compliance Program) is based on (i)
our Core Values of Integrity, Performance, Teamwork and Learning; (ii) the standards contained in
our Business Code of Conduct; (iii) the laws of the countries where we operate; and (iv) our
commitments to the DOJ and the SEC. Our Compliance Program is referenced within the Company as
C2 or Completely Compliant. The Completely Compliant theme is intended to establish
the proper Tone-at-the-Top throughout the Company. Employees are consistently reminded that they
play a crucial role in ensuring that the Company always conducts its business ethically, legally
and safely.
Our Chief Compliance Officer (CCO) oversees the development, administration and enforcement
of our Business Code of Conduct, as well as legal compliance standards, policies, procedures and
processes. The CCO reports directly to the General Counsel and the Chairman of the Audit/Ethics
Committee of our Board of Directors. The CCO has ready access to all of the other senior officers
of the Company. Our legal compliance group of over 30 employees includes our CCO, Global Ethics &
Compliance Director, International Trade Counsel, Region Trade Directors, Region Compliance
Counsel, FCPA due diligence counsel, specialized investigative counsel, as well as labor and
employment counsel. The legal compliance group and our other company attorneys located throughout
the world are available to answer legal questions regarding the Compliance Program and provide
assistance to employees.
32
In connection with our settlements with the DOJ and SEC, we retained an independent monitor to
assess and make recommendations about our compliance policies and procedures. In response to the
monitors initial recommendations, we enhanced and added several elements to our overall Compliance
Program.
Highlights of our Compliance Program, including enhancements or additions as a result of the
independent monitors recommendations, include the following:
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We have a comprehensive employee compliance training program covering substantially all
employees. This includes requiring all employees to take web-based FCPA training and
testing modules, which are available in numerous languages; mandatory global, in-person,
customized training on anti-bribery compliance for key managers, customs/logistics
personnel, sponsors of commercial sales representatives, persons dealing with petty cash,
invoice coding and approval, and expense account approval, sales/marketing personnel dealing
with national oil companies and specially designed training for all new employees. In
addition, our programs allow us to verify the prompt training of new employees regarding our
Core Values, Business Code of Conduct and Compliance Standards; |
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We have comprehensive internal policies over such areas as facilitating payments; travel,
entertainment, gifts and charitable donations connected to non-U.S. government officials;
payments to non-U.S. commercial sales representatives; due diligence procedures for
commercial sales representatives, processing consultants and professional consultants;
non-U.S. community contributions; real estate transactions in selected countries; and the
use of non-U.S. police or military organizations for security purposes. In addition, we
have country-specific guidance for customs standards, export and re-export controls,
economic sanctions and antiboycott laws; |
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We have a compliance council that is comprised of division compliance officers and senior
representatives of the Ethics & Compliance Group. This compliance council is responsible
for assisting the CCO with the strategic direction, ongoing development, coordination, and
implementation of the Compliance Program; |
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We have a special compliance committee composed of the CCO, two Group Presidents, and the
chief financial officer. This Committee meets no less than twice a year to review the
oversight reports for all active commercial sales representatives; |
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We use technology to monitor and report on compliance matters, including a web-based
antiboycott reporting tool and a global trade management software tool currently being
implemented; |
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We have a whistleblower program designed to encourage reporting of any ethics or
compliance matter without fear of retaliation including a worldwide Business Helpline
operated by a third party and currently available toll-free in 150 languages to ensure that
our helpline is easily accessible to employees in their own language; |
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We have a Blue Ribbon Panel comprised of well-known outside experts advising us in the
areas of securities and compliance laws; |
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We have significantly reduced the number of our non-U.S. commercial agents that we use to
conduct our business. For the non-U.S. agents we continue to use, we employ extensive
pre-retention FCPA due diligence requirements, as well as proactive post-retention
oversight; this includes, among other things, the maintenance of comprehensive due diligence
records, and the certification, periodic recertification, and training of all non-U.S.
commercial agents, including written acknowledgement by these agents of all of our FCPA
requirements and policies, and instituting a program to ensure that each of our internal
sponsors regularly reviews their non-U.S. commercial agents, including a review with senior
management; |
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We have adopted a risk-based compliance due diligence procedure for processing and
professional agents, enhancing our process for classifying distributors and creating a
formal policy to guide business personnel in determining when subcontractors should be
subjected to compliance due diligence; |
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We are reviewing and expanding the use of our centralized finance organization, including
further implementation of our enterprise-wide accounting system and company-wide policies
regarding expense reporting, petty cash, the approval of invoice payments and general ledger
account coding; restructured and expanded our corporate audit
function, including
consolidating our divisional audit functions into a centralized audit group; established a
separate anti-corruption group within the audit function and executing separate
anti-corruption audits on a country-wide basis by both legal and audit personnel and
continuing to refine and enhance our procedures for FCPA compliance reviews, risk
assessments, and legal audit procedures; |
33
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We are working to ensure that we have adequate legal compliance coverage around the
world, including the coordination of compliance advice and training across the divisions in
each of our regions; creating simplified summaries to accompany each of our compliance
related policies; supplementing our existing policies and at the same time taking steps to
achieve further centralization of our customs and logistics function, including the
development of uniform and simplified customs policies and procedures, developing uniform
procedures for the verification and documentation of services provided by customs agents and
a training program in which customs and logistics personnel receive specialized training
focused specifically on risks associated with the customs process. We have also adopted a
written plan for reviewing and reducing the number of our customs agents and freight
forwarders; |
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We are continuing to centralize our human resources function, including creating
consistent standards for pre-hire screening of employees, the screening of existing
employees prior to promoting them to positions where they may be exposed to
corruption-related risks and creating a uniform policy for on-boarding training; and |
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We provide a regular and consistent message from senior management of zero tolerance for
FCPA violations, and emphasize that compliance is a positive factor in the continued success
of our business. |
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain adequate financial resources and access
to additional liquidity. During 2008, cash flows from operations were the principal sources of
funding. At December 31, 2008, we had cash and cash equivalents of $1,955 million and $1.0 billion
available through either the committed revolving credit facilities or our commercial paper program.
To the extent we have outstanding commercial paper, our ability to borrow under the committed
revolving credit facilities is reduced. On October 28, 2008, we sold $500 million of 6.50% Senior
Notes that will mature November 15, 2013, and $750 million of 7.50% Senior Notes that will mature
November 15, 2018. We used a portion of the net proceeds to repay $500 million of commercial paper
which matured prior to year end and $525 million aggregate principal amount of our notes that
matured in the first two months of 2009. We believe that the remaining proceeds from the offering,
available cash and cash flows from operations will be sufficient to fund our liquidity needs in
2009. For additional information see Note 12 of the Notes to Consolidated Financial Statements for
a more detailed description of the issuance of the notes.
Our capital planning process is focused on utilizing our existing cash and cash flows
generated from operations in ways that enhance the value of our company. In 2008, we used cash for
a variety of activities including working capital needs, acquisition of businesses, payment of
dividends, share repurchases and capital expenditures.
Cash Flows
Cash flows provided (used) by continuing operations by type of activity were as follows for
the years ended December 31 (in millions):
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2008 |
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2007 |
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2006 |
|
Operating activities |
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$ |
1,614 |
|
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$ |
1,475 |
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$ |
590 |
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Investing activities |
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(1,170 |
) |
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|
(620 |
) |
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|
1,376 |
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Financing activities |
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|
541 |
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|
(593 |
) |
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(1,926 |
) |
Statements of cash flows for entities with international operations that are local currency
functional exclude the effects of the changes in foreign currency exchange rates that occur during
any given year, as these are noncash changes. As a result, changes reflected in certain accounts
on the consolidated statements of cash flows may not reflect the changes in corresponding accounts
on the consolidated balance sheets.
Operating Activities
Cash flows from operating activities of continuing operations provided $1,614 million for the
year ended December 31, 2008 compared with $1,475 million for the year ended December 31, 2007.
Cash flows from operating activities for 2007 were reduced by $125 million for income tax payments
related to the gain on the sale of our interest in WesternGeco. Excluding these income tax
payments, cash flows from operating activities for 2007 were $1,600 million increasing only
slightly in 2008.
The underlying drivers in 2008 of the changes in operating assets and liabilities are as
follows:
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An increase in accounts receivable used $484 million in cash in 2008 compared with using
$287 million in cash in 2007. This increase in accounts receivable was primarily due to the
increase in revenues. Days sales outstanding (defined as the average |
34
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number of days our net trade receivables are outstanding based on quarterly revenues) remained
flat. |
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A build up in inventory related to increased activity used $371 million in cash in 2008
compared with using $142 million in cash in 2007. |
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An increase in accounts payable provided $242 million in cash in 2008 compared with
providing $26 million in cash in 2007. This increase in accounts payable was primarily due
to an increase in operating assets to support increased activity. |
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Accrued employee compensation and other accrued liabilities provided $90 million in cash
in 2008 compared with using $139 million in cash in 2007. The increase in cash was
primarily due to payments made in 2007 that were greater than payments made in 2008
including payments related to employee bonuses, non-income tax liabilities and the payment
of $44 million related to the settlement of the investigations by the SEC and DOJ. |
Our contributions to our defined benefit pension plans in 2008 were $15 million compared to
2007 contributions of $21 million, a decrease of $6 million driven primarily by the change in
exchange rates in non-U.S. locations.
Cash flows from operating activities of continuing operations provided $1,475 million for the
year ended December 31, 2007 compared with $590 million for the year ended December 31, 2006. Cash
flows from operating activities for 2007 and 2006 were reduced by $125 million and $555 million,
respectively, for income tax payments related to the gain on the sale of our interest in
WesternGeco. Excluding these income tax payments, cash flows from operating activities for 2007
and 2006 were $1,600 million and $1,145 million, respectively, an increase of $455 million. This
increase is primarily due to an increase of $198 million in income from continuing operations
adjusted for noncash items coupled with a decrease of $131 million in net operating assets and
liabilities which used less cash.
The underlying drivers in 2007 of the changes in operating assets and liabilities are as
follows:
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An increase in accounts receivable used $287 million in cash in 2007 compared with using
$316 million in cash in 2006. This increase in accounts receivable was primarily due to the
increase in revenues offset partially by an increase in collections as reflected in a
decrease in days sales outstanding (defined as the average number of days our net trade
receivables are outstanding based on quarterly revenues) of approximately one day. |
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A build up in inventory in anticipation of and related to increased activity used $142
million in cash in 2007 compared with using $365 million in cash in 2006. |
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A net decrease in accounts payable, accrued employee compensation and other accrued
liabilities used $113 million in cash in 2007 compared with providing $173 million in cash
in 2006. This was primarily due to higher employee bonus payments made in cash (for bonuses
accrued in 2006 and paid in 2007) coupled with lower bonus accrual requirements for 2007
compared to 2006. The increase in cash used in 2007 was also impacted by the payment of $44
million related to the settlement of the investigations by the SEC and DOJ. |
Our contributions to our defined benefit pension plans in 2007 were approximately $21 million
compared to 2006 contributions of approximately $34 million, a decrease of approximately $13
million. This reduction in contributions is primarily due to lower minimum funding requirements in
our non-U.S. plans.
Investing Activities
Our principal recurring investing activity is the funding of capital expenditures to support
the appropriate levels and types of rental tools we have in place to generate revenues from
operations. Expenditures for capital assets totaled $1,303 million, $1,127 million and $922
million for 2008, 2007 and 2006, respectively. While the majority of these expenditures were for
rental tools, including wireline tools, and machinery and equipment, we have also increased our
spending on new facilities, expansions of existing facilities and other infrastructure projects.
Proceeds from disposal of assets were $222 million, $179 million and $135 million for 2008,
2007 and 2006, respectively. These disposals relate to rental tools that were lost-in-hole, as
well as machinery, rental tools and equipment no longer used in operations that were sold
throughout the year. Included in the proceeds for 2006 was $10 million, related to the sale of
certain real estate properties held for sale.
We routinely evaluate potential acquisitions of businesses of third parties that may enhance
our current operations or expand our operations into new markets or product lines. We may also
from time to time sell business operations that are not considered part of
35
our core business.
In 2008, we sold the assets associated with the Completion and Production segments Surface
Safety Systems product line and received cash proceeds of $31 million. In 2006, we received cash
proceeds of $46 million from the sale of certain businesses, the most significant of which was the
sale of Baker Supply Products Division for $43 million.
During 2008, we paid an aggregate of $120 million for acquisitions of businesses, the most
significant of which were the acquisitions for our reservoir technology and consulting group, in
which we paid cash of $72 million, including $4 million of direct transaction costs and net of cash
acquired of $5 million. As a result of these acquisitions, we recorded $45 million of goodwill and
$45 million of intangible assets.
At December 31, 2008 and 2007, the carrying value, which equals the fair value, of our auction
rate securities (ARS) investments was $11 million and $36 million, respectively. The change of
$25 million reflects an other-than-temporary impairment loss which we recognized in December 2008.
Since September 2007, we have been unable to sell our ARS investments due to unsuccessful auctions.
Based on our ability and intent to hold such investments for a period of time sufficient to allow
for any anticipated recovery in the fair value, we have classified all of our auction rate
securities as noncurrent investments. During 2007, we purchased $2,521 million of and received
proceeds of $2,839 million from maturing auction rate securities.
In 2007, we received $10 million in proceeds from the sale of our equity investment in Toyo
Petrolite Company Ltd. In 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash.
WesternGeco also made a cash distribution of $60 million prior to closing.
In 2006, we paid $66 million for acquisitions of businesses, net of cash acquired, the most
significant of which was Nova Technology Corporation (Nova) for $55 million, net of cash acquired
of $3 million, plus assumed debt.
Financing Activities
We had net borrowings of commercial paper and other short-term debt of $15 million and $14
million in 2008 and 2007, respectively, and net repayments of commercial paper and short-term debt
of $9 million in 2006. Total debt outstanding at December 31, 2008 was $2,333 million, an increase
of $1,249 million compared with December 31, 2007. The total debt to total capitalization (defined
as total debt plus stockholders equity) ratio was 0.25 at December 31, 2008 and 0.15 at
December 31, 2007.
On October 28, 2008, we sold $500 million of 6.50% Senior Notes that will mature
November 15, 2013, and $750 million of 7.50% Senior Notes that will mature November 15, 2018
(collectively, the Notes). Net proceeds from the offering were $1,235 million after deducting
the underwriting discounts and expenses of the offering. We used a portion of the net proceeds to
repay outstanding commercial paper, as well as to repay $325 million aggregate principal amount of
our outstanding 6.25% notes, which matured on January 15, 2009, and $200 million aggregate
principal amount of our outstanding 6.00% notes, which matured on February 15, 2009. We will use
the remaining net proceeds from the offering for general corporate purposes, which could include
funding on-going operations, business acquisitions and repurchases of our common stock. The Notes
are senior unsecured obligations and rank equal in right of payment to all of our existing and
future senior indebtedness; senior in right of payment to any future subordinated indebtedness; and
effectively junior to our future secured indebtedness, if any, and to all existing and future
indebtedness of our subsidiaries. We may redeem, at our option, all or part of the Notes at any
time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date
of redemption.
We received proceeds of $87 million, $67 million and $92 million in 2008, 2007 and 2006,
respectively, from the issuance of common stock through the exercise of stock options and the
employee stock purchase plan.
Our Board of Directors has authorized a program to repurchase our common stock from time to
time. During 2006, we repurchased 24 million shares of our common stock at an average price of
$76.50 per share, for a total of $1,856 million. During 2007, we repurchased 6 million shares of
common stock at an average price of $81.25 per share for a total of $521 million. During 2008, we
repurchased 9 million shares of our common stock at an average price of $68.12 per share for a
total of $627 million. We had authorization remaining to repurchase approximately $1,197 million
in common stock at the end of 2008.
We paid dividends of $173 million, $167 million and $172 million in 2008, 2007 and 2006,
respectively.
Available Credit Facilities
During 2008, we initiated a commercial paper program (the Program) under which we may issue
from time to time unsecured commercial paper notes up to a maximum aggregate amount outstanding at
any time of $1.0 billion. The proceeds of the Program are
36
used for general corporate purposes, including working capital, capital expenditures,
acquisitions and share repurchases. Commercial paper issued under the Program is scheduled to
mature within approximately 270 days of issuance. The commercial paper is not redeemable prior to
maturity and is not subject to voluntary prepayment. At December 31, 2008, we had no outstanding
commercial paper.
On April 1, 2008, we entered into a credit agreement (the 2008 Credit Agreement) for a
committed $500 million revolving credit facility that expires in March 2009. The 2008 Credit
Agreement contains certain covenants, which, among other things, require the maintenance of a
funded indebtedness to total capitalization ratio, restrict certain merger transactions or the sale
of all or substantially all of our assets or a significant subsidiary and limit the amount of
subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under
the 2008 Credit Agreement may be accelerated. Such events of default include payment defaults to
lenders under the 2008 Credit Agreement, covenant defaults and other customary defaults. In March
of 2009, we expect to renew or extend this facility. If we are not
able to renew or extend the
2008 Credit Agreement on acceptable terms, availability under the commercial paper program will
also be reduced by $500 million. However, we believe we will have sufficient borrowing capacity
and liquidity to fund operations.
At December 31, 2008, we had $1,508 million of credit facilities with commercial banks, of
which $1.0 billion are committed revolving credit facilities, which include the 2008 Credit
Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on
March 31, 2009 ($500 million). The $500 million facility that expires on July 7, 2012 provides for
a one year extension, subject to the approval and acceptance by the lenders, among other
conditions. In addition, this facility contains a provision to allow for an increase in the
facility amount of an additional $500 million, subject to the approval and acceptance by the
lenders, among other conditions. Both facilities contain certain covenants which, among other
things, require the maintenance of a funded indebtedness to total capitalization ratio, restrict
certain merger transactions or the sale of all or substantially all of the assets of the Company or
a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of
certain events of default, our obligations under the facilities may be accelerated. Such events of
default include payment defaults to lenders under the facilities, covenant defaults and other
customary defaults.
At December 31, 2008, we were in compliance with all of the covenants of both facilities.
There were no direct borrowings under the facilities during the year ended December 31, 2008;
however, to the extent we have outstanding commercial paper, our ability to borrow under the
facilities is reduced.
If market conditions were to change and revenues were to be significantly reduced or operating
costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could
cause the rating agencies to lower our credit ratings. We do not have any ratings triggers in the
facilities that would accelerate the maturity of any borrowings under these facilities. However, a
downgrade in our credit ratings could increase the cost of borrowings under the facilities and
could also limit or preclude our ability to issue commercial paper. Should this occur, we would
seek alternative sources of funding, including borrowing under the facilities.
We believe our credit ratings and relationships with major commercial and investment banks
would allow us to renew our expiring facility as well as obtain interim financing over and above
our existing credit facilities for any currently unforeseen significant needs or growth
opportunities. We also believe that such interim financings could be funded with subsequent
issuances of long-term debt or equity, if necessary.
Cash Requirements
In 2009, we believe cash on hand and operating cash flows will provide us with sufficient
capital resources and liquidity to manage our working capital needs, meet contractual obligations,
fund capital expenditures, and support the development of our short-term and long-term operating
strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S.
in excess of the cash generated in the U.S.
In 2009, we expect capital expenditures to be between $1.1 billion to $1.2 billion, excluding
acquisitions. The expenditures are expected to be used primarily for normal, recurring items
necessary to support our business and operations. A significant portion of our capital
expenditures can be adjusted based on future activity of our customers. We expect to manage our
capital expenditures to match market demand. In 2009, we also expect to make interest payments of
between $150 million and $155 million, based on debt levels as of December 31, 2008. We anticipate
making income tax payments of between $475 million and $525 million in 2009.
We may repurchase our common stock depending on market conditions, applicable legal
requirements, our liquidity and other considerations. We anticipate paying dividends of between
$180 million and $190 million in 2009; however, the Board of Directors can change the dividend
policy at anytime.
We are not required nor do we intend to make pension contributions to our U.S. qualified
pension plan in 2009. Although we
37
previously expected to forgo contributions for a period of five to eight years, due to recent
downturns in investment markets and the decline in the value of the pension plan assets, we may be
required to make contributions to our U.S. qualified pension plan within the next two to three
years. We do expect to contribute between $2 million and $3 million to our nonqualified U.S.
pension plans and between $12 million and $14 million to the non-U.S. pension plans. We also
expect to make benefit payments related to postretirement welfare plans of between $15 million and
$16 million, and we estimate we will contribute between $139 million and $150 million to our
defined contribution plans. See Note 14 of the Notes to Consolidated Financial Statements in Item
8 herein for further discussion of our employee benefit plans.
Contractual Obligations
In the table below, we set forth our contractual cash obligations as of December 31, 2008.
Certain amounts included in this table are based on our estimates and assumptions about these
obligations, including their duration, anticipated actions by third parties and other factors. The
contractual cash obligations we will actually pay in future periods may vary from those reflected
in the table because the estimates and assumptions are subjective (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
Less Than |
|
2 3 |
|
4 5 |
|
More than |
|
|
Total |
|
1 year |
|
Years |
|
Years |
|
5 Years |
|
Total debt (1) |
|
$ |
2,358 |
|
|
$ |
558 |
|
|
$ |
|
|
|
$ |
500 |
|
|
$ |
1,300 |
|
Estimated interest payments (2) |
|
|
1,508 |
|
|
|
150 |
|
|
|
258 |
|
|
|
258 |
|
|
|
842 |
|
Operating leases(3) |
|
|
476 |
|
|
|
123 |
|
|
|
161 |
|
|
|
74 |
|
|
|
118 |
|
Purchase obligations (4) |
|
|
433 |
|
|
|
412 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
Other long-term liabilities (5) |
|
|
73 |
|
|
|
38 |
|
|
|
12 |
|
|
|
4 |
|
|
|
19 |
|
FIN 48 tax liabilities (6) |
|
|
401 |
|
|
|
97 |
|
|
|
213 |
|
|
|
24 |
|
|
|
67 |
|
|
Total |
|
$ |
5,249 |
|
|
$ |
1,378 |
|
|
$ |
665 |
|
|
$ |
860 |
|
|
$ |
2,346 |
|
|
|
|
|
(1) |
|
Amounts represent the expected cash payments for our total debt and do not include
any unamortized discounts, deferred issuance costs or net deferred gains on terminated
interest rate swap agreements. |
|
(2) |
|
Amounts represent the expected cash payments for interest on our long-term debt. |
|
(3) |
|
We enter into operating leases in the normal course of business. Some lease
agreements provide us with the option to renew the lease. Our future operating lease payments
as reflected in the table above would change if we exercised these renewal options and if we
entered into additional operating lease agreements. |
|
(4) |
|
Purchase obligations include agreements to purchase goods or services that are
enforceable and legally binding and that specify all significant terms, including: fixed or
minimum quantities to be purchased; fixed, minimum or variable price provisions; and the
approximate timing of the transaction. Purchase obligations exclude agreements that are
cancelable at anytime without penalty. |
|
(5) |
|
Amounts represent other long-term liabilities, including the current portion,
reflected in the consolidated balance sheet where both the timing and amount of payment
streams are known. Amounts include: payments for certain environmental remediation
liabilities, payments for deferred compensation, payouts under acquisition agreements and
payments for certain asset retirement obligations. Amounts do not include: payments for
pension contributions and payments for various postretirement welfare benefit plans and
postemployment benefit plans. |
|
(6) |
|
The estimated FIN 48 tax liabilities will be settled as a result of expiring
statutes, audit activity, competent authority proceedings related to transfer pricing, or
final decisions in matters that are the subject of litigation in various taxing jurisdictions
in which we operate. The timing of any particular settlement will depend on the length of the
tax audit and related appeals process, if any, or an expiration of a statute. If a liability
is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48
tax liability would not result in a cash payment. |
38
Off-Balance Sheet Arrangements
In the normal course of business with customers, vendors and others, we have entered into
off-balance sheet arrangements, such as letters of credit and other bank issued guarantees, which
totaled approximately $660 million at December 31, 2008. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts of approximately $433 million at December 31, 2008. It is not practicable to estimate
the fair value of these financial instruments. None of the off-balance sheet arrangements either
has, or is likely to have, a material effect on our consolidated financial statements.
Other than normal operating leases, we do not have any off-balance sheet financing
arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or
special purpose entities. As such, we are not materially exposed to any financing, liquidity,
market or credit risk that could arise if we had engaged in such financing arrangements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of our consolidated financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and expenses and
related disclosures and about contingent assets and liabilities. We base these estimates and
judgments on historical experience and other assumptions and information that are believed to be
reasonable under the circumstances. Estimates and assumptions about future events and their
effects cannot be perceived with certainty, and accordingly, these estimates may change as new
events occur, as more experience is acquired, as additional information is obtained and as the
business environment in which we operate changes.
We have defined a critical accounting estimate as one that is both important to the portrayal
of either our financial condition or results of operations and requires us to make difficult,
subjective or complex judgments or estimates about matters that are uncertain. We have discussed
the development and selection of our critical accounting estimates with the Audit/Ethics Committee
of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented
below. During the past three fiscal years, we have not made any material changes in the
methodology used to establish the critical accounting estimates discussed below, except as required
by the adoption of FIN 48. We believe that the following are the critical accounting estimates
used in the preparation of our consolidated financial statements. In addition, there are other
items within our consolidated financial statements that require estimation but are not deemed
critical as defined above.
Allowance for Doubtful Accounts
The determination of the collectibility of amounts due from our customers requires us to use
estimates and make judgments regarding future events and trends, including monitoring our
customers payment history and current credit worthiness to determine that collectibility is
reasonably assured, as well as consideration of the overall business climate in which our customers
operate. Inherently, these uncertainties require us to make frequent judgments and estimates
regarding our customers ability to pay amounts due us in order to determine the appropriate amount
of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are
recorded when it becomes evident that the customer will not make the required payments at either
contractual due dates or in the future. At December 31, 2008 and 2007, allowance for doubtful
accounts totaled $74 million, or 3%, and $59 million, or 2%, of total gross accounts receivable,
respectively. We believe that our allowance for doubtful accounts is adequate to cover potential
bad debt losses under current conditions; however, uncertainties regarding changes in the financial
condition of our customers, either adverse or positive, could impact the amount and timing of any
additional provisions for doubtful accounts that may be required. A five percent change in the
allowance for doubtful accounts would have had an impact on income from continuing operations
before income taxes of approximately $4 million in 2008.
Inventory Reserves
Inventory is a significant component of current assets and is stated at the lower of cost or
market. This requires us to record provisions and maintain reserves for excess, slow moving and
obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities
on hand and compare them to estimates of future product demand, market conditions, production
requirements and technological developments. These estimates and forecasts inherently include
uncertainties and require us to make judgments regarding potential outcomes. At December 31, 2008
and 2007, inventory reserves totaled $244 million, or 11%, and $221 million, or 11%, of gross
inventory, respectively. We believe that our reserves are adequate to properly value potential
excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated
changes to our estimates and forecasts could impact the amount and timing of any additional
provisions for excess or obsolete inventory that may be required. A five percent change in this
inventory reserve balance would have had an impact on income from continuing operations before
income taxes of approximately $12 million in 2008.
39
Impairment of Long-Lived Assets
Long-lived assets, which include property, goodwill, intangible assets, investments in
affiliates and certain other assets, comprise a significant amount of our total assets. We review
the carrying values of these assets for impairment periodically, and at least annually for
goodwill, 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 us to make judgments regarding long-term
forecasts of future revenues and costs related to the assets subject to review. In turn, these
forecasts are uncertain in that they require assumptions about demand for our products and
services, future market conditions and technological developments. Significant and unanticipated
changes to these assumptions could require a provision for impairment in a future period. Given
the nature of these evaluations and their application to specific assets and specific times, it is
not possible to reasonably quantify the impact of changes in these assumptions.
Income Taxes
The liability method is used for determining our income taxes, under which current and
deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.
Under this method, the amounts of deferred tax liabilities and assets at the end of each period are
determined using the tax rate expected to be in effect when taxes are actually paid or recovered.
Valuation allowances are established to reduce deferred tax assets when it is more likely than not
that some portion or all of the deferred tax assets will not be realized. In determining the need
for valuation allowances, we have considered and made judgments and estimates regarding estimated
future taxable income and ongoing prudent and feasible tax planning strategies. These estimates
and judgments include some degree of uncertainty and changes in these estimates and assumptions
could require us to adjust the valuation allowances for our deferred tax assets. Historically,
changes to valuation allowances have been caused by major changes in the business cycle in certain
countries and changes in local country law. The ultimate realization of the deferred tax assets
depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.
We operate in more than 90 countries under many legal forms. As a result, we are subject to
the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and
treaties among these governments. Our operations in these different jurisdictions are taxed on
various bases: actual income before taxes, deemed profits (which are generally determined using a
percentage of revenues rather than profits) and withholding taxes based on revenue. Determination
of taxable income in any jurisdiction requires the interpretation of the related tax laws and
regulations and the use of estimates and assumptions regarding significant future events such as
the amount, timing and character of deductions, permissible revenue recognition methods under the
tax law and the sources and character of income and tax credits. Changes in tax laws, regulations,
agreements and treaties, foreign currency exchange restrictions or our level of operations or
profitability in each taxing jurisdiction could have an impact on the amount of income taxes that
we provide during any given year.
Our tax filings for various periods are subjected to audit by the tax authorities in most
jurisdictions where we conduct business. These audits may result in assessments of additional
taxes that are resolved with the authorities or through the courts. We believe these assessments
may occasionally be based on erroneous and even arbitrary interpretations of local tax law.
Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we
provide taxes only for the amounts we believe will ultimately result from these proceedings
consistent with the requirements of FIN 48, Accounting for
Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109 (FIN 48). The resulting change to our tax liability, if
any, is dependent on numerous factors that are difficult to estimate. These include, among others,
the amount and nature of additional taxes potentially asserted by local tax authorities; the
willingness of local tax authorities to negotiate a fair settlement through an administrative
process; the impartiality of the local courts; the sheer number of countries in which we do
business; and the potential for changes in the tax paid to one country to either produce, or fail
to produce, an offsetting tax change in other countries. Our experience has been that the
estimates and assumptions we have used to provide for future tax assessments have proven to be
appropriate. However, past experience is only a guide, and the potential exists, however limited,
that the tax resulting from the resolution of current and potential future tax controversies may
differ materially from the amount accrued.
In addition to the aforementioned assessments that have been received from various tax
authorities, we provide for taxes for uncertain tax positions where assessments have not been
received in accordance with FIN 48. We believe such tax reserves are adequate in relation to the
potential for additional assessments. Once established, we adjust these amounts only when more
information is available or when an event occurs necessitating a change to the reserves. Future
events such as changes in the facts or law, judicial decisions regarding the application of
existing law or a favorable audit outcome will result in changes to the amounts provided. We
believe that the resolution of tax matters will not have a material effect on the consolidated
financial condition of the Company, although a resolution could have a material impact on our
consolidated statement of operations for a particular period and on our effective tax rate for any
period in which such resolution occurs.
40
Pensions and Postretirement Benefit Obligations
Pensions and postretirement benefit obligations and the related plan expenses are calculated
using actuarial models and methods. This involves the use of two critical assumptions, the
discount rate and the expected rate of return on assets, both of which are important elements in
determining plan expenses and in measuring plan assets and liabilities. We evaluate these critical
assumptions at least annually. Although considered less critical, other assumptions used in
determining benefit obligations and plan expenses, such as demographic factors like retirement age,
mortality and turnover, are also evaluated periodically and are updated to reflect our actual and
expected experience.
The discount rate enables us to state expected future cash flows at a present value on the
measurement date. The development of the discount rate for our U.S. plans was based on a bond
matching model whereby a hypothetical bond portfolio of high-quality, fixed-income securities is
selected that will match the cash flows underlying the projected benefit obligation. The discount
rate assumption for our non-U.S. plans reflects the market rate for high-quality, fixed-income
securities. A lower discount rate increases the present value of benefit obligations and increases
plan expenses. We used a discount rate of 6.3% in 2008, 6.0% in 2007 and 5.5% in 2006 to determine
plan expenses. A 50 basis point reduction in the discount rate would have decreased income from
continuing operations before income taxes by approximately $2 million in 2008.
To determine the expected rate of return on plan assets, we consider the current and expected
asset allocations, as well as historical and expected returns on various categories of plan assets.
A lower rate of return increases plan expenses. We assumed rates of return on our plan
investments were 8.5% in 2008, 2007 and 2006. A 50 basis point reduction in the expected rate of
return on assets of our principal plans would have decreased income from continuing operations
before income taxes by approximately $4 million in 2008.
NEW ACCOUNTING STANDARDS
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS 157), which is
intended to increase consistency and comparability in fair value measurements by defining fair
value, establishing a framework for measuring fair value and expanding disclosures about fair value
measurements. SFAS 157 was originally effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those fiscal years. In November
2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial
assets and liabilities; however, SFAS 157 is effective for fiscal years beginning after November
15, 2007 for financial assets and liabilities. We adopted all requirements of SFAS 157 on January
1, 2008, except as they relate to nonfinancial assets and liabilities that are not required to be
measured at fair value on a recurring basis. We adopted the remaining requirements of SFAS 157
nonfinancial assets and liabilities on January 1, 2009. The nonfinancial assets and liabilities
include goodwill impairment, impairment and or disposal of long lived assets, asset retirement
obligations, and assets and liabilities relating to business acquisitions. See Note 10 of the
Notes to Consolidated Financial Statements in Item 8 herein for further information on the impact
of this standard.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)
(SFAS 158). SFAS 158 requires an employer to recognize the overfunded or underfunded status of a
defined benefit postretirement plan as an asset or liability in its statement of financial position
and to recognize changes in that funded status in the year in which the changes occur through
comprehensive income. Additionally, it requires an employer to measure the funded status of a plan
as of the date of its year end statement of financial position, with limited exceptions. SFAS 158
is effective as of the end of the fiscal year ending after December 15, 2006; however, the
requirement to measure plan assets and benefit obligations as of the date of the employers fiscal
year end statement of financial position is effective for fiscal years ending after December 15,
2008. We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status
measurement date requirement, which was adopted on December 31, 2008, as allowed under SFAS 158.
The impact of moving our funded status measurement date from October 1st to December
31st was a reduction of $4 million in beginning retained earnings for 2008. See Note 14
of the Notes to Consolidated Financial Statements in Item 8 herein for further information on the
impact of this standard.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities - Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159
permits entities to choose to measure eligible financial assets and liabilities at fair value.
Unrealized gains and losses on items for which the fair value option has been elected are reported
in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We adopted
SFAS 159 on January 1, 2008, and there was no impact on our consolidated financial statements as we
did not choose to measure any eligible financial assets or liabilities at fair value.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial
Statements - an amendment of ARB No. 51 (SFAS 160). SFAS 160 establishes accounting and
reporting standards for the noncontrolling interest in
41
a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance,
comparability and transparency of the financial information that a reporting entity provides in its
consolidated financial statements. SFAS 160 is effective for fiscal years beginning after December
15, 2008. We adopted SFAS 160 on January 1, 2009 with no material impact to our consolidated
financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141R). SFAS 141R replaces FASB Statement No. 141, Business Combinations (SFAS 141). The
statement retains the purchase method of accounting used in business combinations but replaces SFAS
141 by establishing principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction and restructuring costs
related to the acquisition be expensed. In addition, the statement requires disclosures to enable
users to evaluate the nature and financial effects of the business combination. SFAS 141R is
effective for business combinations for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS 141R on
January 1, 2009 for business combinations occurring on or after this date.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities - an amendment of FASB Statement No. 133 (SFAS 161). SFAS 161 requires
qualitative disclosures about objectives and strategies for using derivatives, quantitative data
about the fair value of and gains and losses on derivative contracts, and details of
credit-risk-related contingent features in hedged positions. The statement also requires enhanced
disclosures regarding how and why entities use derivative instruments, how derivative instruments
and related hedged items are accounted for and how derivative instruments and related hedged items
affect entities financial position, financial performance, and cash flows. SFAS 161 is effective
for fiscal years beginning after November 15, 2008. We will adopt the new disclosure requirements
of SFAS 161 in the first quarter of 2009.
In December 2008, the FASB issued FSP FAS 132 (R)-1 Employers Disclosures about
Postretirement Benefit Plan Assets (FSP 132 (R)-1). FSP 132 (R)-1 amends FASB Statement No. 132
(revised 2003), Employers Disclosures about Pensions and Other Postretirement Benefits, to provide
guidance on an employers disclosures about plan assets of a defined benefit pension or other
postretirement plan. This FSP requires the disclosures of investment policies and strategies,
major categories of plan assets, fair value measurement of plan assets and significant
concentration of credit risks. FSP 132 (R)-1 is effective for fiscal years ending after December
15, 2009. We will adopt the new disclosure requirements of FSP 132 (R)-1 in the fourth quarter of
2009.
RELATED PARTY TRANSACTIONS
On April 28, 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash and
recorded a pre-tax gain of $1,744 million ($1,035 million, after-tax). There were no other
significant related party transactions.
FORWARD-LOOKING STATEMENTS
MD&A and certain statements in the Notes to Consolidated Financial Statements include
forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E
of the Exchange Act (each a forward-looking statement). The words anticipate, believe,
ensure, expect, if, intend, estimate, probable, project, forecasts, predict,
outlook, aim, will, could, should, would, may, likely and similar expressions, and
the negative thereof, are intended to identify forward-looking statements. Our forward-looking
statements are based on assumptions that we believe to be reasonable but that may not prove to be
accurate. The statements do not include the potential impact of future transactions, such as an
acquisition, disposition, merger, joint venture or other transaction that could occur. We
undertake no obligation to publicly update or revise any forward-looking statement. Our
expectations regarding our business outlook, including changes in revenue, pricing, capital
spending, profitability, strategies for our operations, impact of any common stock repurchases, oil
and natural gas market conditions, market share and contract terms, costs and availability of
resources, economic and regulatory conditions, and environmental matters are only our forecasts
regarding these matters.
All of our forward-looking information is subject to risks and uncertainties that could cause
actual results to differ materially from the results expected. Although it is not possible to
identify all factors, these risks and uncertainties include the risk factors and the timing of any
of those risk factors identified in the Risk Factors Related to the Worldwide Oil and Natural Gas
Industry and Risk Factors Related to Our Business sections contained in Item 1A. Risk Factors
and those set forth from time to time in our filings with the SEC. These documents are available
through our web site or through the SECs Electronic Data Gathering and Analysis Retrieval System
(EDGAR) at http://www.sec.gov.
42
Risk Factors Related to the Worldwide Oil and Natural Gas Industry
For discussion of our risk factors and cautions regarding forward-looking statements, see the
Risk Factors Related to the Worldwide Oil and Natural Gas Industry in Item 1A. Risk Factors and
in the Forward-Looking Statements section in Item 7, both contained herein. The risk factors
discussed there are not intended to be all inclusive.
Risk Factors Related to Our Business
For discussion of our risk factors and cautions regarding forward-looking statements, see the
Risk Factors Related to Our Business in Item 1A. Risk Factors and in the Forward-Looking
Statements section in Item 7, both contained herein. This list of risk factors is not intended to
be all inclusive.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks that are inherent in our financial instruments and
arise from changes in interest rates and foreign currency exchange rates. We may enter into
derivative financial instrument transactions to manage or reduce market risk but do not enter into
derivative financial instrument transactions for speculative purposes. A discussion of our primary
market risk exposure in financial instruments is presented below.
INTEREST RATE RISK AND INDEBTEDNESS
We are subject to interest rate risk on our long-term fixed interest rate debt. Commercial
paper borrowings, other short-term borrowings and variable rate long-term debt do not give rise to
significant interest rate risk because these borrowings either have maturities of less than three
months or have variable interest rates similar to the interest rates we receive on our short-term
investments. All other things being equal, the fair market value of debt with a fixed interest
rate will increase as interest rates fall and will decrease as interest rates rise. This exposure
to interest rate risk can be managed by borrowing money that has a variable interest rate or using
interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.
At December 31, 2008 and at December 31, 2007, there were no interest rate swap agreements in
effect.
We had fixed rate debt aggregating to $2,325 million at December 31, 2008 and $1,075 million
at December 31, 2007. The following table sets forth the required cash payments for our
indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the
related weighted average effective interest rates by expected maturity dates as of December 31,
2008 and 2007 (dollar amounts in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
Thereafter |
|
Total |
|
|
|
As of December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1) (2) |
|
$ |
|
|
|
$ |
525 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
500 |
|
|
$ |
1,300 |
|
|
$ |
2,325 |
|
Weighted average
effective interest rates |
|
|
|
|
|
|
5.90 |
%(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.73 |
% |
|
|
7.07 |
% |
|
|
7.03 |
%(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1) (2) |
|
$ |
|
|
|
$ |
525 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
550 |
|
|
$ |
1,075 |
|
Weighted average
effective interest rates |
|
|
|
|
|
|
5.24 |
%(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.54 |
% |
|
|
6.40 |
%(3) |
|
|
|
(1) |
|
Amounts do not include any unamortized discounts, deferred issuance costs or net
deferred gains on terminated interest rate swap agreements. |
|
(2) |
|
Fair market value of fixed rate long-term debt was $2,455 million at December 31,
2008 and $1,154 million at December 31, 2007. |
|
(3) |
|
Includes the effect of the amortization of net deferred gains on terminated interest
rate swap agreements. |
FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS
We conduct operations around the world in a number of different currencies. A number of our
significant foreign subsidiaries have designated the local currency as their functional currency.
As such, future earnings are subject to change due to fluctuations in foreign currency exchange
rates when transactions are denominated in currencies other than our subsidiaries respective
functional currencies. To minimize the need for foreign currency forward contracts to hedge this
exposure, our objective is to manage foreign currency exposure by maintaining a minimal
consolidated net asset or net liability position in a currency other than the functional
43
currency. To the extent that market conditions and/or local regulations prevent us from
maintaining a minimal consolidated net asset or net liability position, we may enter into foreign
currency forward contracts or option contracts.
At December 31, 2008, we had entered into several foreign currency forward contracts with
notional amounts aggregating $125 million to hedge exposure to currency fluctuations in various
foreign currency denominated accounts payable and accounts receivable, including the British Pound
Sterling, Norwegian Krone, Euro and the Brazilian Real. These contracts are designated and qualify
as fair value hedging instruments. Based on quoted market prices as of December 31, 2008 for
contracts with similar terms and maturity dates, we recorded a loss of $0.5 million to adjust these
foreign currency forward contracts to their fair market value. This loss offsets designated
foreign currency exchange gains resulting from the underlying exposures and is included in MG&A
expenses in the consolidated statement of operations.
At December 31, 2007, we had entered into several foreign currency forward contracts with
notional amounts aggregating $115 million to hedge exposure to currency fluctuations in various
foreign currency denominated accounts payable and accounts receivable, including the British Pound
Sterling, Norwegian Krone, Euro and the Brazilian Real. These contracts are designated and qualify
as fair value hedging instruments. Based on quoted market prices as of December 31, 2007 for
contracts with similar terms and maturity dates, we recorded a gain of $1 million to adjust these
foreign currency forward contracts to their fair market value. This gain offsets designated
foreign currency exchange losses resulting from the underlying exposures and is included in MG&A
expenses in the consolidated statement of operations.
At December 31, 2007, we had entered into option contracts with notional amounts aggregating
$20 million as a hedge of fluctuations in the Russian Ruble exchange rate. The contracts were not
designated as hedging instruments. Based on quoted market prices as of December 31, 2007 for
contracts with similar terms and maturity dates, we recorded a loss of $0.3 million to adjust the
carrying value of these contracts to their fair market value. This loss is included in MG&A
expenses in our consolidated statement of operations.
The counterparties to our foreign currency forward contracts are major financial institutions.
The credit ratings and concentration of risk of these financial institutions are monitored on a
continuing basis. In the event that the counterparties fail to meet the terms of a foreign
currency contract, our exposure is limited to the foreign currency exchange rate differential.
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Managements Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
our financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Our 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. Our control environment is
the foundation for our system of internal control and is embodied in our Business Code of Conduct,
which sets the tone of our company and includes our Core Values of Integrity, Teamwork, Performance
and Learning. Included in our system of internal control are written policies, an organizational
structure providing division of responsibilities, the selection and training of qualified personnel
and a program of financial and operations reviews by a professional staff of internal auditors.
Our internal control over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of our 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 (iii) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of our assets that could have a material effect on
the financial statements.
Under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, we conducted an evaluation of the effectiveness
of our internal control over financial reporting. Our evaluation was based on the framework in
Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
Based
on our evaluation under the framework in Internal Control - Integrated Framework, our
principal executive officer and principal financial officer concluded that our internal control
over financial reporting was effective as of December 31, 2008. The conclusion of our principal
executive officer and principal financial officer is based on the recognition that there are
inherent limitations in all systems of internal control. Because of the inherent limitations of
internal control over financial reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented
or detected on a timely basis. 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.
Deloitte & Touche LLP, the Companys independent registered public accounting firm, has issued
an attestation report on the effectiveness of the Companys internal control over financial
reporting.
|
|
|
|
|
/s/ CHAD C. DEATON
|
|
/s/ PETER A. RAGAUSS
|
|
/s/ ALAN J. KEIFER |
Chad C. Deaton
|
|
Peter A. Ragauss
|
|
Alan J. Keifer |
Chairman, President and
|
|
Senior Vice President and
|
|
Vice President and |
Chief Executive Officer
|
|
Chief Financial Officer
|
|
Controller |
Houston, Texas
February 25, 2009
45
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
We have audited the internal control over financial reporting of Baker Hughes Incorporated and
subsidiaries (the Company) as of December 31, 2008, based on criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel 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 the inherent limitations of internal control over financial reporting, including
the possibility of collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the 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, the Company maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2008, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and financial statement
schedule II as of and for the year ended December 31, 2008 of the Company and our report dated
February 25, 2009 expressed an unqualified opinion on those financial statements and financial
statement schedule and included an explanatory paragraph regarding the Companys adoption of new
accounting standards.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2009
46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and
subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated
statements of operations, stockholders equity, and cash flows for each of the three years in the
period ended December 31, 2008. Our audits also included financial statement schedule II,
valuation and qualifying accounts, listed in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Companys management. Our
responsibility is to express an opinion on the financial statements and financial statement
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, such consolidated financial statements present fairly, in all material
respects, the financial position of Baker Hughes Incorporated and subsidiaries as of December 31,
2008 and 2007, and the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2008, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a whole, present
fairly, in all material respects, the information set forth therein.
As described in Note 10 to the consolidated financial statements: effective as of January 1,
2008, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 157, which
established new accounting and reporting standards for fair value measurements of certain financial
assets and liabilities. Furthermore, as described in Note 1 to the consolidated financial
statements: effective as of January 1, 2007, the Company adopted Financial Accounting Standards
Board (FASB) AUG AIR-1, which prohibits the accrue-in-advance method of accounting for planned
major maintenance activities; effective as of January 1, 2007, the Company adopted FASB
Interpretation 48, which established new accounting and reporting standards for uncertainty in
income taxes recognized in financial statements.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Companys internal control over financial reporting as of
December 31, 2008, based on the criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 25, 2009 expressed an unqualified opinion on the Companys internal control over financial
reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2009
47
Baker Hughes Incorporated
Consolidated Statements of Operations
(In millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
$ |
5,734 |
|
|
$ |
5,171 |
|
|
$ |
4,566 |
|
Services and rentals |
|
|
6,130 |
|
|
|
5,257 |
|
|
|
4,461 |
|
|
Total revenues |
|
|
11,864 |
|
|
|
10,428 |
|
|
|
9,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
4,081 |
|
|
|
3,517 |
|
|
|
3,033 |
|
Cost of services and rentals |
|
|
3,873 |
|
|
|
3,328 |
|
|
|
2,843 |
|
Research and engineering |
|
|
426 |
|
|
|
372 |
|
|
|
339 |
|
Marketing, general and administrative |
|
|
1,046 |
|
|
|
933 |
|
|
|
878 |
|
Litigation settlement |
|
|
62 |
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
9,488 |
|
|
|
8,150 |
|
|
|
7,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
2,376 |
|
|
|
2,278 |
|
|
|
1,934 |
|
Equity in income of affiliates |
|
|
2 |
|
|
|
1 |
|
|
|
60 |
|
Gain on sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
1,744 |
|
Gain on sale of product line |
|
|
28 |
|
|
|
|
|
|
|
|
|
Impairment loss on investments |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
Interest expense |
|
|
(89 |
) |
|
|
(66 |
) |
|
|
(69 |
) |
Interest and dividend income |
|
|
27 |
|
|
|
44 |
|
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
2,319 |
|
|
|
2,257 |
|
|
|
3,737 |
|
Income taxes |
|
|
(684 |
) |
|
|
(743 |
) |
|
|
(1,338 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
1,635 |
|
|
|
1,514 |
|
|
|
2,399 |
|
Income from discontinued operations, net of tax |
|
|
|
|
|
|
|
|
|
|
20 |
|
|
Net income |
|
$ |
1,635 |
|
|
$ |
1,514 |
|
|
$ |
2,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
5.32 |
|
|
$ |
4.76 |
|
|
$ |
7.26 |
|
Income from discontinued operations |
|
|
|
|
|
|
|
|
|
|
0.06 |
|
|
Net income |
|
$ |
5.32 |
|
|
$ |
4.76 |
|
|
$ |
7.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
5.30 |
|
|
$ |
4.73 |
|
|
$ |
7.21 |
|
Income from discontinued operations |
|
|
|
|
|
|
|
|
|
|
0.06 |
|
|
Net income |
|
$ |
5.30 |
|
|
$ |
4.73 |
|
|
$ |
7.27 |
|
|
See Notes to Consolidated Financial Statements
48
Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except par value)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
1,955 |
|
|
$ |
1,054 |
|
Accounts receivable – less allowance for doubtful accounts
(2008 - $74; 2007 - $59) |
|
|
2,759 |
|
|
|
2,383 |
|
Inventories |
|
|
2,021 |
|
|
|
1,714 |
|
Deferred income taxes |
|
|
231 |
|
|
|
182 |
|
Other current assets |
|
|
179 |
|
|
|
122 |
|
|
Total current assets |
|
|
7,145 |
|
|
|
5,455 |
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment – less accumulated depreciation
(2008 - $3,203; 2007 - $2,976) |
|
|
2,833 |
|
|
|
2,345 |
|
Goodwill |
|
|
1,389 |
|
|
|
1,354 |
|
Intangible assets |
|
|
198 |
|
|
|
177 |
|
Other assets |
|
|
296 |
|
|
|
526 |
|
|
Total assets |
|
$ |
11,861 |
|
|
$ |
9,857 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
888 |
|
|
$ |
704 |
|
Short-term borrowings and current portion of long-term debt |
|
|
558 |
|
|
|
15 |
|
Accrued employee compensation |
|
|
530 |
|
|
|
457 |
|
Income taxes payable |
|
|
272 |
|
|
|
191 |
|
Other accrued liabilities |
|
|
263 |
|
|
|
251 |
|
|
Total current liabilities |
|
|
2,511 |
|
|
|
1,618 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
1,775 |
|
|
|
1,069 |
|
Deferred income taxes and other tax liabilities |
|
|
384 |
|
|
|
416 |
|
Liabilities for pensions and other postretirement benefits |
|
|
317 |
|
|
|
332 |
|
Other liabilities |
|
|
67 |
|
|
|
116 |
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders Equity: |
|
|
|
|
|
|
|
|
Common stock, one dollar par value (shares authorized - 750;
and outstanding: 2008 - 309; 2007 - 316) |
|
|
309 |
|
|
|
316 |
|
Capital in excess of par value |
|
|
745 |
|
|
|
1,216 |
|
Retained earnings |
|
|
6,276 |
|
|
|
4,818 |
|
Accumulated other comprehensive loss |
|
|
(523 |
) |
|
|
(44 |
) |
|
Total stockholders equity |
|
|
6,807 |
|
|
|
6,306 |
|
|
Total liabilities and stockholders equity |
|
$ |
11,861 |
|
|
$ |
9,857 |
|
|
See Notes to Consolidated Financial Statements
49
Baker Hughes Incorporated
Consolidated Statements of Stockholders Equity
(In millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital |
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
in Excess |
|
|
|
|
|
Other |
|
|
|
|
|
|
Common |
|
of |
|
Retained |
|
Comprehensive |
|
Unearned |
|
|
|
|
Stock |
|
Par Value |
|
Earnings |
|
Loss |
|
Compensation |
|
Total |
|
Balance, December 31, 2005 |
|
$ |
342 |
|
|
$ |
3,293 |
|
|
$ |
1,263 |
|
|
$ |
(188 |
) |
|
$ |
(12 |
) |
|
$ |
4,698 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
2,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications included in net income
due to sale of business |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
Translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59 |
|
|
|
|
|
|
|
|
|
Change in minimum pension liability, net of
tax of $7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(18 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,459 |
|
Adoption of
SFAS 158, net
of tax of $22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39 |
) |
|
|
|
|
|
|
(39 |
) |
Adoption of SFAS 123(R) |
|
|
|
|
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
Issuance of
common stock pursuant
to employee
stock plans |
|
|
2 |
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100 |
|
Tax benefit on stock plans |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Stock-based compensation |
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
Repurchase and retirement of common stock |
|
|
(24 |
) |
|
|
(1,832 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,856 |
) |
Cash dividends ($0.52 per share) |
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
|
|
|
|
|
|
|
|
|
(172 |
) |
|
Balance, December 31, 2006 |
|
$ |
320 |
|
|
$ |
1,600 |
|
|
$ |
3,510 |
|
|
$ |
(187 |
) |
|
$ |
|
|
|
$ |
5,243 |
|
Adoption of
AUG AIR-1, net
of tax of $(9) |
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
25 |
|
Adoption of FIN 48 |
|
|
|
|
|
|
|
|
|
|
(64 |
) |
|
|
|
|
|
|
|
|
|
|
(64 |
) |
|
Adjusted beginning balance January 1, 2007 |
|
$ |
320 |
|
|
$ |
1,600 |
|
|
$ |
3,471 |
|
|
$ |
(187 |
) |
|
$ |
|
|
|
$ |
5,204 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
1,514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
|
|
Defined benefit pension plans, net of tax of
$(37) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71 |
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,657 |
|
Issuance of common stock, pursuant to employee
stock plans |
|
|
2 |
|
|
|
66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68 |
|
Tax benefit on stock plans |
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Stock-based compensation |
|
|
|
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46 |
|
Repurchase and retirement of common stock |
|
|
(6 |
) |
|
|
(515 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(521 |
) |
Cash dividends ($0.52 per share) |
|
|
|
|
|
|
|
|
|
|
(167 |
) |
|
|
|
|
|
|
|
|
|
|
(167 |
) |
|
Balance, December 31, 2007 |
|
$ |
316 |
|
|
$ |
1,216 |
|
|
$ |
4,818 |
|
|
$ |
(44 |
) |
|
$ |
|
|
|
$ |
6,306 |
|
Adoption of SFAS 158 |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
Adjusted beginning balance January 1, 2008 |
|
|
316 |
|
|
|
1,216 |
|
|
|
4,814 |
|
|
|
(44 |
) |
|
|
|
|
|
|
6,302 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
1,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(354 |
) |
|
|
|
|
|
|
|
|
Defined benefit pension plans, net of tax
of $67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(125 |
) |
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,156 |
|
Issuance of
common stock, pursuant
to employee stock plans |
|
|
2 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78 |
|
Tax benefit on stock plans |
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
Stock-based compensation |
|
|
|
|
|
|
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60 |
|
Repurchase and retirement of common stock |
|
|
(9 |
) |
|
|
(618 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(627 |
) |
Cash dividends ($0.56 per share) |
|
|
|
|
|
|
|
|
|
|
(173 |
) |
|
|
|
|
|
|
|
|
|
|
(173 |
) |
|
Balance, December 31, 2008 |
|
$ |
309 |
|
|
$ |
745 |
|
|
$ |
6,276 |
|
|
$ |
(523 |
) |
|
$ |
|
|
|
$ |
6,807 |
|
|
See Notes to Consolidated Financial Statements
50
Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
1,635 |
|
|
$ |
1,514 |
|
|
$ |
2,399 |
|
Adjustments to reconcile income from continuing operations to net cash flows from
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
637 |
|
|
|
521 |
|
|
|
434 |
|
Amortization of net deferred gains on derivatives |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
Impairment loss on investments |
|
|
25 |
|
|
|
|
|
|
|
|
|
Stock-based compensation costs |
|
|
60 |
|
|
|
51 |
|
|
|
46 |
|
Acquired in-process research and development |
|
|
|
|
|
|
|
|
|
|
2 |
|
(Benefit)/provision for deferred income taxes |
|
|
(21 |
) |
|
|
(4 |
) |
|
|
78 |
|
Gain on sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
(1,744 |
) |
Provision for income taxes on gain on sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
708 |
|
Gain on sale of product line |
|
|
(28 |
) |
|
|
|
|
|
|
|
|
Gain on disposal of assets |
|
|
(101 |
) |
|
|
(79 |
) |
|
|
(59 |
) |
Equity in income of affiliates |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(60 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(484 |
) |
|
|
(287 |
) |
|
|
(316 |
) |
Inventories |
|
|
(371 |
) |
|
|
(142 |
) |
|
|
(365 |
) |
Accounts payable |
|
|
242 |
|
|
|
26 |
|
|
|
69 |
|
Accrued employee compensation and other accrued liabilities |
|
|
90 |
|
|
|
(139 |
) |
|
|
104 |
|
Income taxes payable |
|
|
76 |
|
|
|
129 |
|
|
|
(98 |
) |
Income taxes paid on sale of interest in affiliate |
|
|
|
|
|
|
(125 |
) |
|
|
(555 |
) |
Liabilities for pensions and other postretirement benefits and other liabilities |
|
|
(38 |
) |
|
|
(4 |
) |
|
|
57 |
|
Other |
|
|
(101 |
) |
|
|
20 |
|
|
|
(105 |
) |
|
Net cash flows from continuing operations |
|
|
1,614 |
|
|
|
1,475 |
|
|
|
590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures for capital assets |
|
|
(1,303 |
) |
|
|
(1,127 |
) |
|
|
(922 |
) |
Purchase of short-term investments |
|
|
|
|
|
|
(2,521 |
) |
|
|
(3,883 |
) |
Proceeds from maturities of short-term investments |
|
|
|
|
|
|
2,839 |
|
|
|
3,606 |
|
Proceeds from disposal of property, plant and equipment |
|
|
222 |
|
|
|
179 |
|
|
|
135 |
|
Proceeds from sale of businesses |
|
|
31 |
|
|
|
|
|
|
|
46 |
|
Acquisition of businesses, net of cash acquired |
|
|
(120 |
) |
|
|
|
|
|
|
(66 |
) |
Proceeds from sale of interests in affiliates |
|
|
|
|
|
|
10 |
|
|
|
2,400 |
|
Distributions from affiliates |
|
|
|
|
|
|
|
|
|
|
60 |
|
|
Net cash flows from investing activities |
|
|
(1,170 |
) |
|
|
(620 |
) |
|
|
1,376 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net borrowings (repayments) of commercial paper and other short-term debt |
|
|
15 |
|
|
|
14 |
|
|
|
(9 |
) |
Proceeds from issuance of long-term debt |
|
|
1,235 |
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock |
|
|
87 |
|
|
|
67 |
|
|
|
92 |
|
Repurchase of common stock |
|
|
(627 |
) |
|
|
(521 |
) |
|
|
(1,856 |
) |
Dividends |
|
|
(173 |
) |
|
|
(167 |
) |
|
|
(172 |
) |
Excess tax benefits from stock-based compensation |
|
|
4 |
|
|
|
14 |
|
|
|
19 |
|
|
Net cash flows from financing activities |
|
|
541 |
|
|
|
(593 |
) |
|
|
(1,926 |
) |
|
Effect of foreign exchange rate changes on cash |
|
|
(84 |
) |
|
|
42 |
|
|
|
13 |
|
|
Increase in cash and cash equivalents |
|
|
901 |
|
|
|
304 |
|
|
|
53 |
|
Cash and cash equivalents, beginning of year |
|
|
1,054 |
|
|
|
750 |
|
|
|
697 |
|
|
Cash and cash equivalents, end of year |
|
$ |
1,955 |
|
|
$ |
1,054 |
|
|
$ |
750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid |
|
$ |
621 |
|
|
$ |
717 |
|
|
$ |
1,198 |
|
Interest paid |
|
$ |
86 |
|
|
$ |
76 |
|
|
$ |
74 |
|
See Notes to Consolidated Financial Statements
51
Baker Hughes Incorporated
Notes to Consolidated Financial Statements
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Baker Hughes Incorporated (Baker Hughes) is engaged in the oilfield services industry. We
are a major supplier of wellbore related products and technology services and systems and provide
products and services for drilling, formation evaluation, completion and production, and reservoir
technology and consulting to the worldwide oil and natural gas industry.
Basis of Presentation
The consolidated financial statements include the accounts of Baker Hughes and all majority
owned subsidiaries (Company, we, our or us). Investments over which we have the ability to
exercise significant influence over operating and financial policies, but do not hold a controlling
interest, are accounted for using the equity method of accounting. All significant intercompany
accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated
Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and
shares, respectively, unless otherwise indicated.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and judgments that
affect the reported amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. We base our estimates and judgments on historical experience
and on various other assumptions and information that are believed to be reasonable under the
circumstances. Estimates and assumptions about future events and their effects cannot be perceived
with certainty and, accordingly, these estimates may change as new events occur, as more experience
is acquired, as additional information is obtained and as our operating environment changes. While
we believe that the estimates and assumptions used in the preparation of the consolidated financial
statements are appropriate, actual results could differ from those estimates. Estimates are used
for, but are not limited to, determining the following: allowance for doubtful accounts and
inventory valuation reserves, recoverability of long-lived assets, useful lives used in
depreciation and amortization, income taxes and related valuation allowances and insurance,
environmental, legal and pensions and postretirement benefit obligations.
Revenue Recognition
Our products and services are generally 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. Our products are produced in a
standard manufacturing operation, even if produced to our customers specifications, and are sold
in the ordinary course of business through our regular marketing channels. We recognize revenue
for these products upon delivery, when title passes, when collectibility is reasonably assured and
there are no further significant obligations for future performance. Provisions for estimated
warranty returns or similar types of items are made at the time the related revenue is recognized.
Revenue for services and rentals is recognized as the services are rendered and when collectibility
is reasonably assured. Rates for services are typically priced on a per day, per meter, per man
hour or similar basis.
Cost of Sales and Cost of Services and Rentals
Cost of sales and cost of services and rentals include material, labor, selling and field
service costs, and overhead costs associated with the manufacture and distribution of our products
for sale or rental. Distribution costs include freight costs, purchasing and receiving costs,
warehousing costs and other costs of our distribution network.
Research and Engineering
Research and engineering expenses include costs associated with the research and development
of new products and services and costs associated with sustaining engineering of existing products
and services. These costs are expensed as incurred and include research and development costs for
new products and services of $263 million, $234 million and $216 million for the year ended
December 31, 2008, 2007 and 2006, respectively.
52
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Marketing, General and Administrative
Marketing, general and administrative (MG&A) expenses include all advertising and marketing
efforts, business development costs, and other general and administrative costs not directly
associated with the manufacture and distribution of our products for sale or rental and the
employee related costs associated with these functions. MG&A expenses also include gains and
losses from foreign currency transactions.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at
the time of purchase to be cash equivalents.
Investments
Prior to September 2007, we invested in auction rate securities, which are variable-rate debt
securities. While the underlying security has a long-term maturity, the interest rate is reset
through Dutch auctions that are typically held every 7, 28 or 35 days. Interest is paid at the end
of each auction period. We limited our investments in auction rate securities (ARS) to non
mortgage-backed securities that, at the time of the initial investment, carried a AAA (or
equivalent) rating from a recognized rating agency. Since September 2007, we have been unable to
sell our ARS investments because of unsuccessful auctions. As a result, the interest rate now
resets every 28 days at one month LIBOR plus a spread determined by each certificates lowest
assigned rating and the liquidity of these investments has been diminished. During 2008, we
recorded an other-than-temporary impairment loss on these investments of $25 million, which is
reflected in our consolidated statement of operations. At December 31, 2008 and 2007, we held ARS
investments totaling $11 million and $36 million, respectively. Our ARS investments are classified
as noncurrent investments, which are included in other assets in our consolidated balance sheet.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first-in,
first-out (FIFO) method or the average cost method, which approximates FIFO, and includes the
cost of materials, labor and manufacturing overhead.
Property, Plant and Equipment and Accumulated Depreciation
Property, plant and equipment (PP&E) is stated at cost less accumulated depreciation, which
is generally provided by using the straight-line method over the estimated useful lives of the
individual assets. Significant improvements and betterments are capitalized if they extend the
useful life of the asset. We manufacture a substantial portion of our rental tools and equipment
and the cost of these items, which includes direct and indirect manufacturing costs, are
capitalized and carried in inventory until the tool is completed. Once the tool has been
completed, the cost of the tool is reflected in capital expenditures and the tool is classified as
rental tools and equipment in PP&E. Maintenance and repairs are charged to expense as incurred.
The capitalized costs of computer software developed or purchased for internal use are classified
in machinery and equipment in PP&E.
In 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (FSP AUG AIR-1), which prohibits
the use of the accrue-in-advance method of accounting for planned major maintenance and repair
activities. We adopted FSP AUG AIR-1 on January 1, 2007, to change our method of accounting for
repairs and maintenance activities on certain rental tools from the accrue-in-advance method to the
direct expense method. The adoption resulted in an increase of $25 million to beginning retained
earnings as of January 1, 2007. We did not restate any prior periods as the impact was not
material to our consolidated financial statements.
Asset Retirement Obligations
Legal obligations associated with the retirement of long-lived assets are to be recognized at
their fair value at the time that the obligations are incurred. Upon initial recognition of a
liability, that cost is capitalized as part of the related long-lived asset and depreciated on a
straight-line basis over the remaining estimated useful life of the related asset. Accretion
expense in connection with the discounted liability is also recognized over the remaining useful life of the related asset. Asset retirement obligations were $17 million and
$16 million at December 31, 2008 and 2007, respectively.
53
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Goodwill, Intangible Assets and Amortization
Goodwill and intangible assets with indefinite lives are not amortized. Intangible assets
with finite useful lives are amortized on a basis that reflects the pattern in which the economic
benefits of the intangible assets are realized, which is generally on a straight-line basis over
the assets estimated useful life.
Impairment of Long-Lived Assets
We review PP&E, intangible assets and certain other assets for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. The
determination of recoverability is made based upon the estimated undiscounted future net cash
flows, excluding interest expense. The amount of impairment loss, if any, is determined by
comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value
of the related assets.
We perform an annual impairment test of goodwill for each of our reporting units as of October
1, or more frequently if circumstances indicate an impairment may exist. Our reporting units are
based on our organizational and reporting structure. Corporate and other assets and liabilities
are allocated to the reporting units to the extent that they relate to the operations of those
reporting units in determining their carrying amount. Investments in affiliates are also reviewed
for impairment whenever events or changes in circumstances indicate that impairment may exist. The
determination of impairment is made by comparing the carrying amount with its fair value, which is
calculated using a combination of a market capitalization and discounted cash flow approach.
Income Taxes
We use the liability method for determining our income taxes, under which current and deferred
tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this
method, the amounts of deferred tax liabilities and assets at the end of each period are determined
using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax
benefits are recognized to the extent that realization of such benefits is more likely than not.
Deferred income taxes are provided for the estimated income tax effect of temporary
differences between financial and tax bases in assets and liabilities. Deferred tax assets are
also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax
assets is established when it is more likely than not that some portion or all of the deferred tax
assets will not be realized.
We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations
outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We
do provide for the U.S. and additional non-U.S. taxes on earnings anticipated to be repatriated
from our non-U.S. subsidiaries.
We operate in more than 90 countries under many legal forms. As a result, we are subject to
the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and
treaties among these governments. Our operations in these different jurisdictions are taxed on
various bases: actual income before taxes, deemed profits (which are generally determined using a
percentage of revenues rather than profits) and withholding taxes based on revenue. Determination
of taxable income in any jurisdiction requires the interpretation of the related tax laws and
regulations and the use of estimates and assumptions regarding significant future events, such as
the amount, timing and character of deductions, permissible revenue recognition methods under the
tax law and the sources and character of income and tax credits. Changes in tax laws, regulations,
agreements and treaties, foreign currency exchange restrictions or our level of operations or
profitability in each tax jurisdiction could have an impact upon the amount of income taxes that we
provide during any given year.
Our tax filings for various periods are subjected to audit by tax authorities in most
jurisdictions where we conduct business. These audits may result in assessments of additional
taxes that are resolved with the authorities or through the courts. We believe that these
assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax
law. We have received tax assessments from various tax authorities and are currently at varying
stages of appeals and/or litigation regarding these matters. We have provided for the amounts we
believe will ultimately result from these proceedings. We believe we have substantial defenses to
the questions being raised and will pursue all legal remedies should an unfavorable outcome result.
However, resolution of these matters involves uncertainties and there are no assurances that the
outcomes will be favorable. We provide for uncertain tax positions pursuant to FIN 48, Accounting
for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.
54
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
The Financial Accounting Standards Board (FASB) issued FIN 48 in July 2006. FIN 48 provides
that a tax benefit from an uncertain tax position may be recognized when it is more likely than not
that the position will be sustained upon examination, including resolutions of any related appeals
or litigation processes, based on the technical merits. The interpretation also provides guidance
on measurement, derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition. We adopted the provisions of FIN 48 effective January 1, 2007,
pursuant to which we recognized a $78 million increase in the gross liability for unrecognized tax
benefits, a $14 million increase in non-current tax receivables, and a net decrease to beginning
retained earnings of $64 million.
Product Warranties
We sell certain products with a product warranty that provides that customers can return a
defective product during a specified warranty period following the purchase in exchange for a
replacement product, repair at no cost to the customer or the issuance of a credit to the customer.
We accrue amounts for estimated warranty claims based upon current and historical product sales
data, warranty costs incurred and any other related information known to us. Our product warranty
liability was $8 million and $15 million at December 31, 2008 and 2007, respectively.
Environmental Matters
Estimated remediation costs are accrued using currently available facts, existing
environmental permits, technology and presently enacted laws and regulations. For sites where we
are primarily responsible for the remediation, our cost estimates are developed based on internal
evaluations and are not discounted. Accruals are recorded when it is probable that we will be
obligated to pay for environmental site evaluation, remediation or related activities, and such
costs can be reasonably estimated. If the obligation can only be estimated within a range, we
accrue the minimum amount in the range. Accruals are recorded even if significant uncertainties
exist over the ultimate cost of the remediation. As additional or more accurate information
becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental
compliance costs, such as obtaining environmental permits, installation of pollution control
equipment and waste disposal, are expensed as incurred. Where we have been identified as a
potentially responsible party in a United States federal or state Superfund site, we accrue our
share of the estimated remediation costs of the site. This share is based on the ratio of the
estimated volume of waste we contributed to the site to the total volume of waste disposed at the
site.
Foreign Currency
A number of our significant foreign subsidiaries have designated the local currency as their
functional currency and, as such, gains and losses resulting from balance sheet translation of
foreign operations are included as a separate component of accumulated other comprehensive loss
within stockholders equity. Gains and losses from foreign currency transactions, such as those
resulting from the settlement of receivables or payables in the non-functional currency, are
included in MG&A expenses in the consolidated statements of operations as incurred. For those
foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and
losses resulting from balance sheet translation of foreign operations are also included in MG&A
expense in the consolidated statements of operations as incurred.
Derivative Financial Instruments
We monitor our exposure to various business risks including commodity prices, foreign currency
exchange rates and interest rates and occasionally use derivative financial instruments to manage
these risks. Our policies do not permit the use of derivative financial instruments for
speculative purposes. We use foreign currency forward contracts to hedge certain firm commitments
and transactions denominated in foreign currencies. We have used and may use interest rate swaps
to manage interest rate risk.
At the inception of any new derivative, we designate the derivative as a hedge as that term is
defined in SFAS 133 (as amended and interpreted) Accounting for Derivative Instruments and Hedging
Activities or we determine the derivative to be undesignated as a hedging instrument as the facts
dictate. We document all relationships between the hedging instruments and the hedged items, as
well as our risk management objectives and strategy for undertaking various hedge transactions. We
assess whether the derivatives that are used in hedging transactions are highly effective in
offsetting changes in cash flows of the hedged item at both the inception of the hedge and on an
ongoing basis.
55
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
New Accounting Standards
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS 157), which is
intended to increase consistency and comparability in fair value measurements by defining fair
value, establishing a framework for measuring fair value and expanding disclosures about fair value
measurements. SFAS 157 was originally effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those fiscal years. In November
2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial
assets and liabilities; however, SFAS 157 is effective for fiscal years beginning after November
15, 2007 for financial assets and liabilities. We adopted all requirements of SFAS 157 on January
1, 2008, except as they relate to nonfinancial assets and liabilities that are not required to be
measured at fair value on a recurring basis. We adopted the remaining requirements of SFAS 157
nonfinancial assets and liabilities on January 1, 2009. The nonfinancial assets and liabilities
include goodwill impairment, impairment and or disposal of long lived assets, asset retirement
obligations, and assets and liabilities relating to business acquisitions. See Note 10. Fair
Value of Certain Financial Assets and Liabilities for further information on the impact of this
standard.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)
(SFAS 158). SFAS 158 requires an employer to recognize the overfunded or underfunded status of a
defined benefit postretirement plan as an asset or liability in its statement of financial position
and to recognize changes in that funded status in the year in which the changes occur through
comprehensive income. Additionally, it requires an employer to measure the funded status of a plan
as of the date of its year end statement of financial position, with limited exceptions. SFAS 158
is effective as of the end of the fiscal year ending after December 15, 2006; however, the
requirement to measure plan assets and benefit obligations as of the date of the employers fiscal
year end statement of financial position is effective for fiscal years ending after December 15,
2008. We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status
measurement date requirement, which was adopted on December 31, 2008, as allowed under SFAS 158.
The impact of moving our funded status measurement date from October 1st to December
31st was a reduction of $4 million in beginning retained earnings for 2008. See Note
14. Employee Benefit Plans for further information on the impact of this standard.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and
Financial Liabilities - Including an amendment of FASB Statement No. 115 (SFAS 159). SFAS 159
permits entities to choose to measure eligible financial assets and liabilities at fair value.
Unrealized gains and losses on items for which the fair value option has been elected are reported
in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We adopted
SFAS 159 on January 1, 2008, and there was no impact on our consolidated financial statements as we
did not choose to measure any eligible financial assets or liabilities at fair value.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements - an amendment of ARB No. 51 (SFAS 160). SFAS 160 establishes accounting
and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation
of a subsidiary in an effort to improve the relevance, comparability and transparency of the
financial information that a reporting entity provides in its consolidated financial statements.
SFAS 160 is effective for fiscal years beginning after December 15, 2008. We adopted SFAS 160 on
January 1, 2009 with no material impact to our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141R). SFAS 141R replaces FASB Statement No. 141, Business Combinations (SFAS 141). The
statement retains the purchase method of accounting used in business combinations but replaces SFAS
141 by establishing principles and requirements for the recognition and measurement of assets,
liabilities and goodwill, including the requirement that most transaction and restructuring costs
related to the acquisition be expensed. In addition, the statement requires disclosures to enable
users to evaluate the nature and financial effects of the business combination. SFAS 141R is
effective for business combinations for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS 141R on
January 1, 2009 for business combinations occurring on or after this date.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities - an amendment of FASB Statement No. 133 (SFAS 161). SFAS 161 requires
qualitative disclosures about objectives and strategies for using derivatives, quantitative data
about the fair value of and gains and losses on derivative contracts, and details of
credit-risk-related contingent features in hedged positions. The statement also requires enhanced
disclosures regarding how and why entities use derivative instruments, how derivative instruments
and related hedged items are accounted for and how derivative instruments and related hedged items
affect entities financial position, financial performance, and cash flows. SFAS 161 is effective
for fiscal years beginning after November 15, 2008. We will adopt the new disclosure requirements
of SFAS 161 in the first quarter of 2009.
56
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
In December 2008, the FASB issued FSP FAS 132(R)-1 Employers Disclosures about Postretirement
Benefit Plan Assets (FSP 132(R)-1). FSP 132(R)-1 amends FASB Statement No. 132 (revised 2003),
Employers Disclosures about Pensions and Other Postretirement Benefits, to provide guidance on an
employers disclosures about plan assets of a defined benefit pension or other postretirement plan.
This FSP requires the disclosures of investment policies and strategies, major categories of plan
assets, fair value measurement of plan assets and significant concentration of credit risks. FSP
132(R)-1 is effective for fiscal years ending after December 15, 2009. We will adopt the new
disclosure requirements of FSP 132(R)-1 in the fourth quarter of 2009.
NOTE 2. DISPOSITIONS AND DISCONTINUED OPERATIONS
In February 2008, we sold the assets associated with the Completion and Production segments
Surface Safety Systems (SSS) product line and received cash proceeds of $31 million. The SSS
assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We
recorded a pre-tax gain of $28 million ($18 million after-tax).
We have investments in affiliates that are accounted for using the equity method of
accounting. In 2006, the most significant of these affiliates was our 30% interest in WesternGeco,
a seismic venture jointly owned with Schlumberger Limited (Schlumberger). On April 28, 2006, we
sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in cash. We recorded a
pre-tax gain of $1,744 million ($1,035 million after-tax). Prior to our sale, during 2006 we
received distributions of $60 million from WesternGeco, which were recorded as reductions in the
carrying value of our investment.
In the fourth quarter of 2005, our management initiated and our Board of Directors approved a
plan to sell the Baker Supply Products Division (Baker SPD), a product line group within the
Completion and Production segment, which distributes basic supplies, products and small tools to
the drilling industry. In March 2006, we completed the sale of Baker SPD and received cash
proceeds of $43 million. Income from discontinued operations for 2006 was $20 million, which
included the after-tax gain of $19 million. There were no discontinued operations in 2007 or 2008.
NOTE 3. ACQUISITIONS
In April 2008, we acquired two firms for our reservoir technology and consulting group -
Gaffney, Cline & Associates (GCA) and GeoMechanics
International (GMI) - for $72 million in
cash, including $4 million of direct transaction costs and net of cash acquired of $5 million.
These firms provide consulting services related to reservoir engineering, technical and managerial
advisory services and reservoir geomechanics. As a result of these acquisitions, we recorded $43
million of goodwill and $19 million of intangibles. Under the terms of the purchase agreements, we
may be required to make additional payments of up to approximately $46 million based on the
performance of the businesses during 2008, 2009 and 2010. During 2008, we made several other
acquisitions having an aggregate purchase price of $53 million, of which $48 million was paid in
cash. As a result of these acquisitions, we recorded $2 million of goodwill and $26 million of
intangible assets through December 31, 2008.
In January 2006, we acquired Nova Technology Corporation (Nova) for $55 million, net of cash
acquired of $3 million, plus assumed debt. Nova is a supplier of permanent monitoring, chemical
injection systems, and multi-line services for deepwater and subsea oil and gas well applications.
As a result of the acquisition, we recorded $30 million of goodwill, $24 million of intangible
assets and assigned $2 million to in-process research and development.
For each of these acquisitions, the purchase price was allocated based on the fair value of the
assets acquired and liabilities assumed using a discounted cash flow approach. Amounts related to
in-process research and development were written off at the date of acquisition and are included in
research and engineering expenses. Pro forma results of operations have not been presented
individually or in the aggregate for these acquisitions because the effects of these acquisitions
were not material to our consolidated financial statements.
57
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 4. STOCK-BASED COMPENSATION
Stock-based compensation cost is measured at the date of grant, based on the calculated fair
value of the award, and is recognized as expense over the employees service period, which is
generally the vesting period of the equity grant. Additionally, compensation cost is recognized
based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated
forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant
and revised, if necessary, in subsequent periods to reflect actual forfeitures.
The following table summarizes stock-based compensation costs for the years ended December 31,
2008, 2007 and 2006. There were no stock-based compensation costs capitalized as the amounts were
not material.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Stock-based compensation costs |
|
$ |
60 |
|
|
$ |
51 |
|
|
$ |
46 |
|
Tax benefit |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
(10 |
) |
|
Stock-based compensation costs, net of tax |
|
$ |
49 |
|
|
$ |
40 |
|
|
$ |
36 |
|
|
For our stock options and restricted stock awards and units, we currently have 17 million
shares authorized for issuance and as of December 31, 2008, approximately 6 million shares were
available for future grants. Our policy is to issue new shares for exercises of stock options;
vesting of restricted stock awards and units; and issuances under the employee stock purchase plan.
Stock Options
Our stock option plans provide for the issuance of incentive and non-qualified stock options
to directors, officers and other key employees at an exercise price equal to the fair market value
of the stock at the date of grant. Although subject to the terms of the stock option agreement,
substantially all of the stock options become exercisable in three equal annual installments,
beginning a year from the date of grant, and generally expire ten years from the date of grant.
The stock option plans provide for the acceleration of vesting upon the employees retirement;
therefore, the service period is reduced for employees that are or will become retirement eligible
during the vesting period and, accordingly, the recognition of compensation expense for these
employees is accelerated. Compensation cost related to stock options is recognized on a
straight-line basis over the vesting or service period and is net of forfeitures.
The fair value of each stock option granted is estimated on the date of grant using the
Black-Scholes option pricing model. The following table presents the weighted average assumptions
used in the option pricing model for options granted. The expected life of the options represents
the period of time the options are expected to be outstanding. The expected life is based on our
historical exercise trends and post-vest termination data incorporated into a forward-looking stock
price model. As allowed under the Securities and Exchange Commissions Staff Accounting Bulletin
107 (SAB 107), the expected volatility is based on our implied volatility, which is the
volatility forecast that is implied by the prices of our actively traded options to purchase our
stock observed in the market. The risk-free interest rate is based on the observed U.S. Treasury
yield curve in effect at the time the options were granted. The dividend yield is based on our
history of dividend payouts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Expected life (years) |
|
|
5.5 |
|
|
|
5.1 |
|
|
|
5.0 |
|
Risk-free interest rate |
|
|
3.1 |
% |
|
|
4.8 |
% |
|
|
4.8 |
% |
Volatility |
|
|
31.4 |
% |
|
|
28.6 |
% |
|
|
31.1 |
% |
Dividend yield |
|
|
0.8 |
% |
|
|
0.7 |
% |
|
|
0.7 |
% |
Weighted average fair value per share at grant date |
|
$ |
23.64 |
|
|
$ |
24.20 |
|
|
$ |
26.15 |
|
58
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
A summary of our stock option activity and related information is presented below (in
thousands, except per option prices):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Exercise Price |
|
|
Number of Options |
|
Per Option |
|
Outstanding at December 31, 2007 |
|
|
3,171 |
|
|
$ |
55.25 |
|
Granted |
|
|
699 |
|
|
|
73.56 |
|
Exercised |
|
|
(355 |
) |
|
|
45.73 |
|
Forfeited |
|
|
(26 |
) |
|
|
74.40 |
|
Expired |
|
|
(19 |
) |
|
|
26.10 |
|
|
Outstanding at December 31, 2008 |
|
|
3,470 |
|
|
$ |
59.92 |
|
|
The total intrinsic value of stock options (defined as the amount by which the market price of
the underlying stock on the date of exercise exceeds the exercise price of the option) exercised in
2008, 2007 and 2006 was $13 million, $73 million and $74 million, respectively. The income tax
benefit realized from stock options exercised was $7 million for the year ended December 31, 2008.
The total fair value of options vested in 2008, 2007 and 2006 was $17 million, $20 million and
$20 million, respectively. As of December 31, 2008, there was $10 million of total unrecognized
compensation cost related to nonvested stock options which is expected to be recognized over a
weighted average period of 2 years.
The following table summarizes information about stock options outstanding as of December 31,
2008 (in thousands, except per option prices and remaining life):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
Exercisable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
Weighted |
|
|
|
|
|
Average |
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
Average |
|
|
|
|
|
Remaining |
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual |
|
Exercise |
|
|
|
|
|
Contractual |
|
Exercise |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Life |
|
Price Per |
|
Number of |
|
Life |
|
Price Per |
Range of Exercise Prices |
|
|
|
Options |
|
(In years) |
|
Option |
|
Options |
|
(In years) |
|
Option |
|
$ |
14.49 |
|
|
|
|
|
|
$ |
16.78 |
|
|
|
|
|
8 |
|
|
|
2.5 |
|
|
$ |
15.62 |
|
|
|
8 |
|
|
|
2.5 |
|
|
$ |
15.62 |
|
|
22.88 |
|
|
|
|
|
|
|
33.29 |
|
|
|
|
|
337 |
|
|
|
3.7 |
|
|
|
29.79 |
|
|
|
337 |
|
|
|
3.7 |
|
|
|
29.79 |
|
|
34.95 |
|
|
|
|
|
|
|
43.39 |
|
|
|
|
|
865 |
|
|
|
5.3 |
|
|
|
40.25 |
|
|
|
860 |
|
|
|
5.4 |
|
|
|
40.26 |
|
|
56.21 |
|
|
|
|
|
|
|
82.28 |
|
|
|
|
|
2,237 |
|
|
|
8.1 |
|
|
|
71.95 |
|
|
|
995 |
|
|
|
7.2 |
|
|
|
68.54 |
|
|
86.50 |
|
|
|
|
|
|
|
86.50 |
|
|
|
|
|
23 |
|
|
|
9.6 |
|
|
|
86.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
3,470 |
|
|
|
7.0 |
|
|
$ |
59.92 |
|
|
|
2,200 |
|
|
|
6.0 |
|
|
$ |
51.36 |
|
|
The aggregate intrinsic value of stock options outstanding at December 31, 2008 was $2
million, all of which relates to options vested and exercisable. The intrinsic value for stock
options outstanding is calculated as the amount by which the quoted price of $34.33 of our common
stock as of the end of 2008 exceeds the exercise price of the options.
Restricted Stock Awards and Units
In addition to stock options, officers, directors and key employees may be granted restricted
stock awards (RSA), which is an award of common stock with no exercise price, or restricted stock
units (RSU), where each unit represents the right to receive at the end of a stipulated period
one unrestricted share of stock with no exercise price. RSAs and RSUs are subject to cliff or
graded vesting, generally ranging over a three to five year period. We determine the fair value of
restricted stock awards and restricted stock units based on the market price of our common stock on
the date of grant. Compensation cost for RSAs and RSUs is primarily recognized on a straight-line
basis over the vesting or service period and is net of forfeitures.
59
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
A summary of our RSA and RSU activity and related information is presented below (in
thousands, except per share/unit prices):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
|
|
|
Average |
|
|
RSA |
|
Grant Date |
|
RSU |
|
Grant Date |
|
|
Number of |
|
Fair Value |
|
Number of |
|
Fair Value |
|
|
Shares |
|
Per Share |
|
Units |
|
Per Unit |
|
Nonvested balance at December 31, 2007 |
|
|
795 |
|
|
$ |
61.93 |
|
|
|
156 |
|
|
$ |
66.56 |
|
Granted |
|
|
527 |
|
|
|
72.82 |
|
|
|
258 |
|
|
|
75.96 |
|
Vested |
|
|
(359 |
) |
|
|
69.85 |
|
|
|
(74 |
) |
|
|
71.58 |
|
Forfeited |
|
|
(61 |
) |
|
|
61.53 |
|
|
|
(15 |
) |
|
|
70.66 |
|
|
Nonvested balance at December 31, 2008 |
|
|
902 |
|
|
$ |
65.17 |
|
|
|
325 |
|
|
$ |
72.68 |
|
|
The weighted average grant date fair value per share for RSAs in 2008, 2007 and 2006 was
$72.82, $61.93 and $73.97, respectively. The weighted average grant date fair value per unit for
RSUs in 2008, 2007 and 2006 was $75.96, $66.56 and $74.00, respectively.
The total grant date fair value of RSAs and RSUs vested in 2008, 2007 and 2006 was $30
million, $16 million and $11 million, respectively. As of December 31, 2008, there was $37 million
and $16 million of total unrecognized compensation cost related to nonvested RSAs and RSUs,
respectively, which is expected to be recognized over a weighted average period of 2 years.
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan (ESPP) allows eligible employees to elect to contribute on an
after-tax basis between 1% and 10% of their annual pay to purchase our common stock; provided,
however, an employee may not contribute more than $25,000 annually to the plan pursuant to Internal
Revenue Service restrictions. Shares are purchased at a 15% discount of the fair market value of
our common stock on January 1 or December 31, whichever is lower. We initially had 14.5 million
shares authorized for issuance under the ESPP, and at December 31, 2008, there were 1.0 million
shares reserved for future issuance under the ESPP. At the April 2009 Annual Meeting of
Stockholders, we are asking the stockholders to approve an amendment to the ESPP to increase the
shares authorized for issuance under the ESPP by 8 million shares. Compensation expense determined
under SFAS 123(R) for the year ended December 31, 2008 was calculated using the Black-Scholes
option pricing model with the following assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Expected life (years) |
|
|
1.0 |
|
|
|
1.0 |
|
|
|
1.0 |
|
Risk-free interest rate |
|
|
3.2 |
% |
|
|
4.9 |
% |
|
|
4.4 |
% |
Volatility |
|
|
32.8 |
% |
|
|
30.5 |
% |
|
|
28.0 |
% |
Dividend yield |
|
|
0.6 |
% |
|
|
0.7 |
% |
|
|
0.9 |
% |
Weighted average fair value per share at grant date |
|
$ |
11.43 |
|
|
$ |
10.39 |
|
|
$ |
7.66 |
|
We calculated estimated volatility using historical daily prices based on the expected life of
the stock purchase plan. The risk-free interest rate is based on the observed U.S. Treasury yield
curve in effect at the time the ESPP shares were granted. The dividend yield is based on our
history of dividend payouts.
60
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 5. INCOME TAXES
The provision for income taxes on income from continuing operations is comprised of the
following for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
292 |
|
|
$ |
366 |
|
|
$ |
861 |
|
Foreign |
|
|
413 |
|
|
|
381 |
|
|
|
371 |
|
|
Total current |
|
|
705 |
|
|
|
747 |
|
|
|
1,232 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
(14 |
) |
|
|
19 |
|
|
|
98 |
|
Foreign |
|
|
(7 |
) |
|
|
(23 |
) |
|
|
8 |
|
|
Total deferred |
|
|
(21 |
) |
|
|
(4 |
) |
|
|
106 |
|
|
Provision for income taxes |
|
$ |
684 |
|
|
$ |
743 |
|
|
$ |
1,338 |
|
|
The geographic sources of income from continuing operations before income taxes are as follows
for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
United States |
|
$ |
795 |
|
|
$ |
877 |
|
|
$ |
1,917 |
|
Foreign |
|
|
1,524 |
|
|
|
1,380 |
|
|
|
1,820 |
|
|
Income from continuing operations
before income taxes |
|
$ |
2,319 |
|
|
$ |
2,257 |
|
|
$ |
3,737 |
|
|
The provision for income taxes differs from the amount computed by applying the U.S. statutory
income tax rate to income from continuing operations before income taxes for the reasons set forth
below for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Statutory income tax at 35% |
|
$ |
812 |
|
|
$ |
790 |
|
|
$ |
1,308 |
|
Effect of sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
98 |
|
Effect of foreign operations |
|
|
(134 |
) |
|
|
(84 |
) |
|
|
(87 |
) |
Net tax (benefit) charge related to foreign losses |
|
|
3 |
|
|
|
(1 |
) |
|
|
(3 |
) |
State income
taxes - net of U.S. tax benefit |
|
|
19 |
|
|
|
18 |
|
|
|
12 |
|
Other - net |
|
|
(16 |
) |
|
|
20 |
|
|
|
10 |
|
|
Provision for income taxes |
|
$ |
684 |
|
|
$ |
743 |
|
|
$ |
1,338 |
|
|
During 2006, we provided $708 million for taxes related to the sale of our interest in
WesternGeco. Approximately $98 million of this tax provision is in excess of the U.S. statutory
income tax rate due to taxes provided on the expected repatriation of the non-U.S. proceeds
received in the transaction and a larger U.S. tax gain due to lower tax basis compared to book
basis.
61
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Deferred income taxes reflect the net tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects
of our temporary differences and carryforwards are as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Receivables |
|
$ |
9 |
|
|
$ |
6 |
|
Inventory |
|
|
206 |
|
|
|
160 |
|
Property |
|
|
71 |
|
|
|
50 |
|
Employee benefits |
|
|
124 |
|
|
|
29 |
|
Other accrued expenses |
|
|
35 |
|
|
|
45 |
|
Operating loss carryforwards |
|
|
36 |
|
|
|
44 |
|
Tax credit carryforwards |
|
|
54 |
|
|
|
31 |
|
Capitalized research and development costs |
|
|
16 |
|
|
|
28 |
|
Other |
|
|
55 |
|
|
|
39 |
|
|
Subtotal |
|
|
606 |
|
|
|
432 |
|
Valuation allowances |
|
|
(77 |
) |
|
|
(67 |
) |
|
Total |
|
|
529 |
|
|
|
365 |
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Goodwill |
|
|
139 |
|
|
|
133 |
|
Undistributed earnings of foreign subsidiaries |
|
|
124 |
|
|
|
99 |
|
Other |
|
|
45 |
|
|
|
49 |
|
|
Total |
|
|
308 |
|
|
|
281 |
|
|
Net deferred tax asset |
|
$ |
221 |
|
|
$ |
84 |
|
|
We record a valuation allowance when it is more likely than not that some portion or all of
the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets
depends on the ability to generate sufficient taxable income of the appropriate character in the
future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for
operating loss and foreign tax credit carryforwards in certain non-U.S. jurisdictions. The
operating loss carryforwards without a valuation allowance will expire in varying amounts over the
next twenty years.
We have provided for U.S. and additional foreign taxes for the anticipated repatriation of
certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our
foreign subsidiaries above the amount for which taxes have already been provided to be indefinitely
reinvested, as we have no intention to repatriate these earnings. As such, deferred income taxes
are not provided for temporary differences of approximately $2.2 billion, $1.6 billion and $0.8
billion as of December 31, 2008, 2007 and 2006, respectively, representing earnings of non-U.S.
subsidiaries intended to be permanently reinvested. These additional foreign earnings could become
subject to additional tax if remitted, or deemed remitted, as a dividend. Computation of the
potential deferred tax liability associated with these undistributed earnings and other basis
difference is not practicable.
At December 31, 2008, we had approximately $45 million of foreign tax credits which may be
carried forward indefinitely under applicable foreign law and $8 million of foreign tax credits
available to offset future payments of federal income taxes, expiring in 2018. In addition, at
December 31, 2008, we had approximately $1 million of state tax credits expiring in varying amounts
between 2016 and 2021.
We provide for uncertain tax positions pursuant to FIN 48, Accounting for Uncertainty in
Income Taxes: an Interpretation of FASB Statement No. 109. As of December 31, 2008, we had $401
million of tax liabilities for gross unrecognized tax benefits, which includes liabilities for
interest and penalties of $63 million and $15 million, respectively. If we were to prevail on all
uncertain tax positions, the net effect would be a benefit to our effective tax rate of
approximately $323 million. The remaining approximately $78 million, which is recorded as a
deferred tax asset, represents tax benefits that would be received in different taxing
jurisdictions in the event that we did not prevail on all uncertain tax positions.
As of December 31, 2007, we had $457 million of tax liabilities for gross unrecognized tax
benefits, which includes liabilities for interest and penalties of $72 million and $22 million,
respectively. Our gross unrecognized tax benefits include $9 million of additional taxes and
related interest and penalties, recorded in 2007, that are associated with disallowed tax
deductions taken in previous years, arising from the resolution of investigations with the
Securities and Exchange Commission (SEC) and the
62
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Department of Justice (DOJ). If we were to prevail on all uncertain tax positions, the net
effect would be a benefit to our effective tax rate of approximately $373 million. The remaining
approximately $84 million, which is recorded as a deferred tax asset, represents tax benefits that
would be received in different taxing jurisdictions in the event that we did not prevail on all
uncertain tax positions.
We have elected under FIN 48 to continue with our prior policy to classify interest and
penalties related to unrecognized tax benefits as income taxes in our financial statements. For
the year ended December 31, 2008, we recognized a benefit of $16 million for interest and penalties
related to unrecognized tax benefits in the consolidated statement of operations.
The following presents a rollforward of our unrecognized tax benefits and associated interest
and penalties included in the balance sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
|
|
Unrecognized |
|
|
|
|
|
|
|
|
Tax Benefits, |
|
|
|
|
|
|
|
|
Excluding |
|
|
|
|
|
Total Gross |
|
|
Interest and |
|
Interest and |
|
Unrecognized |
|
|
Penalties |
|
Penalties |
|
Tax Benefits |
|
Balance at January 1, 2007 |
|
$ |
354 |
|
|
$ |
69 |
|
|
$ |
423 |
|
Increase in prior year tax positions |
|
|
3 |
|
|
|
21 |
|
|
|
24 |
|
Increase in current year tax positions |
|
|
20 |
|
|
|
5 |
|
|
|
25 |
|
Decrease related to settlements with taxing
authorities and lapse of statute of limitations |
|
|
(22 |
) |
|
|
(5 |
) |
|
|
(27 |
) |
Increase due to effects of foreign currency translation |
|
|
8 |
|
|
|
4 |
|
|
|
12 |
|
|
Balance at January 1, 2008 |
|
$ |
363 |
|
|
$ |
94 |
|
|
$ |
457 |
|
Increase/(decrease) in prior year tax positions |
|
|
(7 |
) |
|
|
10 |
|
|
|
3 |
|
Increase in current year tax positions |
|
|
17 |
|
|
|
5 |
|
|
|
22 |
|
Decrease related to settlements with taxing authorities |
|
|
(24 |
) |
|
|
(10 |
) |
|
|
(34 |
) |
Decrease related to lapse of statute of limitations |
|
|
(20 |
) |
|
|
(17 |
) |
|
|
(37 |
) |
Decrease due to effects of foreign currency translation |
|
|
(6 |
) |
|
|
(4 |
) |
|
|
(10 |
) |
|
Balance at December 31, 2008 |
|
$ |
323 |
|
|
$ |
78 |
|
|
$ |
401 |
|
|
It is expected that the amount of unrecognized tax benefits will change in the next twelve
months due to expiring statutes, audit activity, tax payments, competent authority proceedings
related to transfer pricing, or final decisions in matters that are the subject of litigation in
various taxing jurisdictions in which we operate. At December 31, 2008, we had approximately $77
million of tax liabilities, net of $20 million of tax assets, related to uncertain tax provisions,
each of which are individually insignificant, and each of which are reasonably possible of being
settled within the next twelve months primarily as the result of audit settlements or statute
expirations in several taxing jurisdictions.
At December 31, 2008, approximately $304 million of gross unrecognized tax benefits were
included in the non-current portion of our income tax liabilities, for which the settlement period
cannot be determined; however, it is not expected to be within the next twelve months.
We operate in over 90 countries and are subject to income taxes in most taxing jurisdictions
in which we operate. The following table summarizes the earliest tax years that remain subject to
examination by the major taxing jurisdictions in which we operate. These jurisdictions are those
we project to have the highest tax liability for 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
Earliest Open Tax |
|
|
|
Earliest Open Tax |
Jurisdiction |
|
Period |
|
Jurisdiction |
|
Period |
|
Canada
|
|
|
1998 |
|
|
Norway
|
|
|
1999 |
|
Germany
|
|
|
2003 |
|
|
United Kingdom
|
|
|
2004 |
|
Netherlands
|
|
|
1998 |
|
|
United States
|
|
|
2002 |
|
63
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 6. EARNINGS PER SHARE
A reconciliation of the number of shares used for the basic and diluted EPS computations is as
follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Weighted average common shares outstanding for basic EPS |
|
|
307 |
|
|
|
318 |
|
|
|
331 |
|
Effect of
dilutive securities – stock plans |
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
Adjusted weighted average common shares outstanding for diluted EPS |
|
|
309 |
|
|
|
320 |
|
|
|
333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future potentially dilutive shares excluded from diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Options with an exercise price greater than the average market
price for the period |
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
NOTE 7. INVENTORIES
Inventories are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
Finished goods |
|
$ |
1,693 |
|
|
$ |
1,414 |
|
Work in process |
|
|
175 |
|
|
|
177 |
|
Raw materials |
|
|
153 |
|
|
|
123 |
|
|
Total |
|
$ |
2,021 |
|
|
$ |
1,714 |
|
|
NOTE 8. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
Period |
|
2008 |
|
2007 |
|
Land |
|
|
|
|
|
$ |
85 |
|
|
$ |
62 |
|
Buildings and improvements |
|
1 – 30 years |
|
|
878 |
|
|
|
775 |
|
Machinery and equipment |
|
1 – 20 years |
|
|
3,082 |
|
|
|
2,745 |
|
Rental tools and equipment |
|
1 – 15 years |
|
|
1,991 |
|
|
|
1,739 |
|
|
Subtotal |
|
|
|
|
|
|
6,036 |
|
|
|
5,321 |
|
Accumulated depreciation |
|
|
|
|
|
|
(3,203 |
) |
|
|
(2,976 |
) |
|
Total |
|
|
|
|
|
$ |
2,833 |
|
|
$ |
2,345 |
|
|
64
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 9. GOODWILL AND INTANGIBLE ASSETS
The changes in the carrying amount of goodwill are detailed below by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
Completion |
|
|
|
|
and Evaluation |
|
and Production |
|
Total |
|
Balance as of December 31, 2006 |
|
$ |
909 |
|
|
$ |
438 |
|
|
$ |
1,347 |
|
Purchase price and other adjustments |
|
|
2 |
|
|
|
1 |
|
|
|
3 |
|
Impact of foreign currency translation adjustments |
|
|
3 |
|
|
|
1 |
|
|
|
4 |
|
|
Balance as of December 31, 2007 |
|
|
914 |
|
|
|
440 |
|
|
|
1,354 |
|
Goodwill acquired during the period |
|
|
45 |
|
|
|
|
|
|
|
45 |
|
Purchase price and other adjustments |
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Impact of foreign currency translation adjustments |
|
|
(17 |
) |
|
|
(2 |
) |
|
|
(19 |
) |
|
Balance as of December 31, 2008 |
|
$ |
951 |
|
|
$ |
438 |
|
|
$ |
1,389 |
|
|
We perform an annual impairment test of goodwill as of October 1 of every year. There were no
impairments of goodwill in 2008, 2007 or 2006 related to the annual impairment test.
Intangible assets are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
|
Gross |
|
|
|
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
Carrying |
|
Accumulated |
|
|
|
|
|
Carrying |
|
Accumulated |
|
|
|
|
Amount |
|
Amortization |
|
Net |
|
Amount |
|
Amortization |
|
Net |
|
Technology-based |
|
$ |
256 |
|
|
$ |
(122 |
) |
|
$ |
134 |
|
|
$ |
241 |
|
|
$ |
(105 |
) |
|
$ |
136 |
|
Contract-based |
|
|
12 |
|
|
|
(7 |
) |
|
|
5 |
|
|
|
15 |
|
|
|
(9 |
) |
|
|
6 |
|
Marketing-related |
|
|
33 |
|
|
|
(6 |
) |
|
|
27 |
|
|
|
6 |
|
|
|
(6 |
) |
|
|
|
|
Customer-based |
|
|
37 |
|
|
|
(5 |
) |
|
|
32 |
|
|
|
14 |
|
|
|
(4 |
) |
|
|
10 |
|
Other |
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amortizable intangible assets |
|
|
339 |
|
|
|
(141 |
) |
|
|
198 |
|
|
|
276 |
|
|
|
(124 |
) |
|
|
152 |
|
|
Marketing-related intangible assets
with indefinite useful lives |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
25 |
|
|
Total |
|
$ |
339 |
|
|
$ |
(141 |
) |
|
$ |
198 |
|
|
$ |
301 |
|
|
$ |
(124 |
) |
|
$ |
177 |
|
|
Intangible assets are amortized either on a straight-line basis with estimated useful lives
ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits
of the intangible assets are expected to be realized, which range from 15 to 30 years.
Amortization expense included in net income for the years ended December 31, 2008, 2007 and
2006 was $20 million, $21 million and $20 million, respectively. Estimated amortization expense
for each of the subsequent five fiscal years is expected to be as
follows: 2009 - $25 million;
2010 - $23 million; 2011 - $20 million; 2012 -
$18 million; and 2013 - $15 million.
NOTE 10. FAIR VALUE OF CERTAIN FINANCIAL ASSETS AND LIABILITIES
On January 1, 2008, we adopted the methods of determining fair value as described in SFAS 157
to value certain of our financial assets and liabilities. SFAS 157 defines fair value as the price
that would be received to sell an asset or paid to transfer a liability (an exit price) in an
orderly transaction between market participants at the reporting date. The statement establishes
consistency and comparability by providing a fair value hierarchy that prioritizes the inputs to
valuation techniques into three broad levels, which are described below:
|
|
|
Level 1 inputs are quoted market prices in active markets for identical assets or
liabilities (these are observable market inputs). |
|
|
|
|
Level 2 inputs are inputs other than quoted prices included within Level 1 that are
observable for the asset or liability (includes quoted market prices for similar assets or
identical or similar assets in markets in which there are few transactions, prices that are
not current or vary substantially). |
65
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
|
|
|
Level 3 inputs are unobservable inputs that reflect the entitys own assumptions in
pricing the asset or liability (used when little or no market data is available). |
SFAS 157 requires the use of observable market inputs (quoted market prices) when measuring
fair value whenever possible and requires a Level 1 quoted price be used to measure fair value
whenever possible.
Financial assets and liabilities included in our financial statements and measured at fair
value as of December 31, 2008 are classified based on the valuation technique level in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement at |
|
|
|
|
|
|
December 31, 2008 |
Description |
|
Total |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Auction rate securities |
|
$ |
11 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
11 |
|
Non-qualified defined contribution plan assets |
|
|
112 |
|
|
|
|
|
|
|
112 |
|
|
|
|
|
|
Total assets at fair value |
|
$ |
123 |
|
|
$ |
|
|
|
$ |
112 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-qualified defined contribution plan
liabilities |
|
$ |
112 |
|
|
$ |
|
|
|
$ |
112 |
|
|
$ |
|
|
|
The following is a reconciliation of activity for the period for assets measured at fair value
based on significant unobservable Inputs (Level 3).
|
|
|
|
|
|
|
Level 3 |
|
|
Fair Value Measurements |
|
|
Auction Rate Securities |
|
Balance as of December 31, 2007 |
|
$ |
36 |
|
|
Total gains or (losses) realized: |
|
|
|
|
Included in earnings (or changes to net assets) |
|
|
(25 |
) |
Included in other comprehensive income |
|
|
|
|
|
Balance as of December 31, 2008 |
|
$ |
11 |
|
|
Auction Rate Securities
Until July 2007, the Company invested in auction rate securities (ARS) that represent
interests in three variable rate debt securities. These are credit linked notes and generally
combine low risk assets and credit default swaps (CDS) to create a security that pays interest
from the assets coupon payments and the periodic sale proceeds of the CDS. As of
December 31, 2008, the three notes carried split ratings ranging from A to BB, as provided by
Standard & Poors and Fitch rating agencies. Since September 2007, we have been unable to sell our
ARS investments because of unsuccessful auctions. Liquidity for these auction rate securities is
typically provided by an auction process that resets the applicable interest rate at pre-determined
intervals, usually every 7, 28, or 35 days. As a result of the unsuccessful auctions and the
downgrade in credit quality, the interest rate for each certificate resets every 28 days at one
month LIBOR plus a spread determined by each certificates lowest assigned rating.
We utilized Level 3 inputs to estimate the fair value of our ARS investments based on the
underlying structure of each security and their collateral values, including assessments of
counterparty credit quality, default risk underlying the security, expected cash flows, discount
rates and overall capital market liquidity. Based on this analysis, we recorded an
other-than-temporary impairment loss of $25 million, which is included in our consolidated
statement of operations. The valuation of our ARS investments is subject to uncertainties that are
difficult to predict and require significant judgment. The fair value of our ARS investments could
change significantly in the future based on various factors including changes to credit ratings of
the securities as well as to the underlying assets supporting those securities, rates of default of
the underlying assets, underlying collateral value, discount rates, counterparty risk or if
auctions were to resume. Based on our ability and intent to hold such investments for a period of
time sufficient to allow for any anticipated recovery in the fair value, we have classified all of
our auction rate securities as noncurrent investments.
66
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Non-qualified Defined Contribution Plan Assets and Liabilities
We have a non-qualified defined contribution plan that provides basically the same benefit as
our Thrift Plan for certain non-U.S. employees who are not eligible to participate in the Thrift
Plan. In addition, we provide a non-qualified supplemental retirement plan for certain officers
and employees whose benefits under the Thrift Plan and/or U.S. defined benefit pension plan are
limited by federal tax law. The assets of both plans consist primarily of mutual funds and to a
lesser extent equity securities. We hold the assets of these plans under a grantor trust and have
recorded the assets along with the related deferred compensation liability at fair value. The
assets and liabilities were valued using Level 2 inputs at the reporting date and were based on
quoted market prices from various major stock exchanges.
Nonfinancial Assets and Liabilities
In November 2007, the FASB placed a one year deferral for the implementation of SFAS 157 for
nonfinancial assets and liabilities. Accordingly, we adopted the methods of determining fair value
described in SFAS 157 as applicable for nonfinancial assets and liabilities beginning
January 1, 2009.
NOTE 11. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Our financial instruments include cash and short-term investments, noncurrent investments in
auction rate securities, accounts receivable, accounts payable, debt, foreign currency forward
contracts and foreign currency option contracts. Except as described below, the estimated fair
value of such financial instruments at December 31, 2008 and 2007 approximates their carrying value
as reflected in our consolidated balance sheets. The fair value of our debt and foreign currency
forward contracts has been estimated based on quoted year end market prices.
The estimated fair value of total debt at December 31, 2008 and 2007 was $2,471 million and
$1,170 million, respectively, which differs from the carrying amounts of $2,333 million and $1,084
million, respectively, included in our consolidated balance sheets.
Foreign Currency Forward Contracts
At December 31, 2008, we had entered into several foreign currency forward contracts with
notional amounts aggregating $125 million to hedge exposure to currency fluctuations in various
foreign currencies, including British Pound Sterling, Euro, Norwegian Krone and the Brazilian Real.
These contracts are designated and qualify as fair value hedging instruments. Based on quoted
market prices as of December 31, 2008 for contracts with similar terms and maturity dates, we
recorded a loss of $0.5 million to adjust these foreign currency forward contracts to their fair
market value. This loss offsets designated foreign exchange gains resulting from the underlying
exposures and is included in MG&A expenses in our consolidated statement of operations.
At December 31, 2007, we had entered into several foreign currency forward contracts with
notional amounts aggregating $115 million to hedge exposure to currency fluctuations in various
foreign currency denominated accounts payable and accounts receivable, including the British Pound
Sterling, Norwegian Krone, Euro and the Brazilian Real. These contracts are designated and qualify
as fair value hedging instruments. Based on quoted market prices as of December 31, 2007 for
contracts with similar terms and maturity dates, we recorded a gain of $1 million to adjust these
foreign currency forward contracts to their fair market value. This gain offsets designated
foreign currency exchange losses resulting from the underlying exposures and is included in MG&A
expenses in the consolidated statement of operations.
At December 31, 2007, we had entered into option contracts with notional amounts aggregating
$20 million as a hedge of fluctuations in the Russian Ruble exchange rate. The contracts were not
designated as hedging instruments. Based on quoted market prices as of December 31, 2007 for
contracts with similar terms and maturity dates, we recorded a loss of $0.3 million to adjust the
carrying value of these contracts to their fair market value. This loss is included in MG&A
expenses in our consolidated statement of operations.
The counterparties to our foreign currency forward contracts are financial institutions. We
monitor the credit ratings and our concentration of risk with these financial institutions on a
continuing basis. In the event that the counterparties fail to meet the terms of a foreign
currency contract, our exposure is limited to the foreign currency exchange rate differential.
67
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Concentration of Credit Risk
We sell our products and services to numerous companies in the oil and natural gas industry.
Although this concentration could affect our overall exposure to credit risk, we believe that our
risk is minimized since the majority of our business is conducted with major companies within the
industry. We perform periodic credit evaluations of our customers financial condition and
generally do not require collateral for our accounts receivable. In some cases, we will require
payment in advance or security in the form of a letter of credit or bank guarantee.
We maintain cash deposits with financial institutions that may exceed federally insured
limits. We monitor the credit ratings and our concentration of risk with these financial
institutions on a continuing basis to safeguard our cash deposits.
NOTE 12. INDEBTEDNESS
Total debt consisted of the following at December 31, net of unamortized discount and debt
issuance costs:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
6.25% Notes due January 2009 with an effective interest rate of 5.77% |
|
$ |
325 |
|
|
$ |
330 |
|
|
|
|
|
|
|
|
|
|
6.00% Notes due February 2009 with an effective interest rate of 6.11% |
|
|
200 |
|
|
|
200 |
|
|
|
|
|
|
|
|
|
|
6.50% Senior Notes due November 2013 with an effective interest rate of 6.73% |
|
|
495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.50% Senior Notes due November 2018 with an effective interest rate of 7.67% |
|
|
740 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.55% Debentures due June 2024 with an effective interest rate of 8.76% |
|
|
148 |
|
|
|
147 |
|
|
|
|
|
|
|
|
|
|
6.875% Notes due January 2029 with an effective interest rate of 7.08% |
|
|
392 |
|
|
|
392 |
|
|
|
|
|
|
|
|
|
|
Other debt |
|
|
33 |
|
|
|
15 |
|
|
Total debt |
|
|
2,333 |
|
|
|
1,084 |
|
Less short-term debt and current maturities of long-term debt |
|
|
558 |
|
|
|
15 |
|
|
Long-term debt |
|
$ |
1,775 |
|
|
$ |
1,069 |
|
|
On April 1, 2008, we entered into a credit agreement (the 2008 Credit Agreement) for a
committed $500 million revolving credit facility that expires in March 2009. The 2008 Credit
Agreement contains certain covenants, which, among other things, require the maintenance of a
funded indebtedness to total capitalization ratio (a defined formula per the agreement) of less
than or equal to 0.60, restrict certain merger transactions or the sale of all or substantially all
of our assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon
the occurrence of certain events of default, our obligations under the 2008 Credit Agreement may be
accelerated. Such events of default include payment defaults to lenders under the 2008 Credit
Agreement, covenant defaults and other customary defaults. In March of 2009, we expect to renew or
extend this facility. If we are not able to renew or extend the 2008 Credit Agreement on
acceptable terms, availability under the commercial paper program will also be reduced by $500
million.
At December 31, 2008, we had $1,508 million of credit facilities with commercial banks, of
which $1.0 billion are committed revolving credit facilities, which includes the 2008 Credit
Agreement. The committed facilities expire on July 7, 2012 ($500 million), unless extended, and on
March 31, 2009 ($500 million). The $500 million facility that expires on July 7, 2012 provides for
a one year extension, subject to the approval and acceptance by the lenders, among other
conditions. In addition, this facility contains a provision to allow for an increase in the
facility amount of an additional $500 million, subject to the approval and acceptance by the
lenders, among other conditions. Both facilities contain certain covenants which, among other
things, require the maintenance of a funded indebtedness to total capitalization ratio, restrict
certain merger transactions or the sale of all or substantially all of the assets of the Company or
a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of
certain events of default, our obligations under the facilities may be accelerated. Such events of
default include payment defaults to lenders under the facilities, covenant defaults and other
customary defaults.
At December 31, 2008, we were in compliance with all of the covenants of both facilities.
There were no direct borrowings under the facilities during the year ended December 31, 2008;
however, to the extent we have outstanding commercial paper, our ability to borrow under the
facilities is reduced.
68
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
On March 3, 2008, we initiated a commercial paper program (the Program) under which we may
issue from time to time unsecured commercial paper notes up to a maximum aggregate amount
outstanding at any time of $500 million. On April 2, 2008, we increased the Program to an
aggregate of $1.0 billion. The proceeds of the Program are used for general corporate purposes,
including working capital, capital expenditures, acquisitions and share repurchases. Commercial
paper issued under the Program is scheduled to mature within approximately 270 days of issuance.
The commercial paper is not redeemable prior to maturity and will not be subject to voluntary
prepayment. At December 31, 2008, we had no outstanding commercial paper.
On October 28, 2008, we sold $500 million of 6.50% Senior Notes that will mature
November 15, 2013, and $750 million of 7.50% Senior Notes that will mature November 15, 2018
(collectively, the Notes). Net proceeds from the offering were $1,235 million after deducting
the underwriting discounts and expenses of the offering. We used a portion of the net proceeds to
repay outstanding commercial paper, as well as to repay $325 million aggregate principal amount of
our outstanding 6.25% notes, which matured on January 15, 2009, and $200 million aggregate
principal amount of our outstanding 6.00% notes, which matured on February 15, 2009. We will use
the remaining net proceeds from the offering for general corporate purposes, which could include
funding on-going operations, business acquisitions and repurchases of our common stock. Interest
on the Notes is payable May 15 and November 15 of each year. The first interest payment will be
made on May 15, 2009, and will consist of accrued interest from October 28, 2008. The Notes are
senior unsecured obligations and rank equal in right of payment to all of our existing and future
senior indebtedness; senior in right of payment to any future subordinated indebtedness; and
effectively junior to our future secured indebtedness, if any, and to all existing and future
indebtedness of our subsidiaries. We may redeem, at our option, all or part of the Notes at any
time, at the applicable make-whole redemption prices plus accrued and unpaid interest to the date
of redemption.
In prior years, we terminated various interest rate swap agreements prior to their scheduled
maturities resulting in net gains. The net gains were deferred and are being amortized as a net
reduction of interest expense over the remaining life of the underlying debt securities. The
unamortized net deferred gains of $0.2 million and $5 million are included in the 6.25% Notes due
January 2009 in the consolidated balance sheets at December 31, 2008 and 2007, respectively.
Maturities
of debt at December 31, 2008 are as follows: 2009 -
$558 million; 2010 - $0
million; 2011 - $0 million; 2012 - $0 million, 2013 - $495 million; and $1,280 million thereafter.
NOTE 13. SEGMENT AND RELATED INFORMATION
We are a major supplier of wellbore related products and technology services and systems and
provide products and services for drilling, formation evaluation, completion and production, and
reservoir technology and consulting to the worldwide oil and natural gas industry. We report
results for our product-line focused divisions under two segments: the Drilling and Evaluation
segment and the Completion and Production segment. We have aggregated the divisions within each
segment because they have similar economic characteristics and because the long-term financial
performance of these divisions is affected by similar economic conditions. They also operate in
the same markets, which includes all of the major oil and natural gas producing regions of the
world. The results of each segment are evaluated regularly by our chief operating decision maker
in deciding how to allocate resources and in assessing performance. The accounting policies of our
segments are the same as those described in Note 1 of Notes to Consolidated Financial Statements.
|
|
|
The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids
(drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling,
measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation
evaluation and wireline completion services) divisions and also includes our reservoir
technology and consulting group. The Drilling and Evaluation segment provides products and
services used to drill and evaluate oil and natural gas wells as well as consulting
services used in the analysis of oil and gas reservoirs. |
|
|
|
|
The Completion and Production segment consists of the Baker Oil Tools (workover, fishing
and completion equipment), Baker Petrolite (oilfield specialty chemicals), Centrilift
(electrical submersible pumps and progressing cavity pumps) divisions, the ProductionQuest
(production optimization and permanent monitoring) business unit and Integrated Operations
and Project Management. The Completion and Production segment provides equipment and
services used from the completion phase through the productive life of oil and natural gas
wells. |
The performance of our segments is evaluated based on segment profit (loss), which is defined
as income from continuing operations before income taxes, interest expense, interest and dividend
income and certain gains and losses not allocated to the segments.
69
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Summarized financial information is shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
Completion |
|
|
|
|
|
|
|
|
and |
|
and |
|
Oilfield |
|
Corporate |
|
|
|
|
Evaluation |
|
Production |
|
Operations |
|
and Other |
|
Total |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
6,049 |
|
|
$ |
5,815 |
|
|
$ |
11,864 |
|
|
$ |
|
|
|
$ |
11,864 |
|
Equity in income of affiliates |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Segment profit (loss) |
|
|
1,398 |
|
|
|
1,282 |
|
|
|
2,680 |
|
|
|
(361 |
) |
|
|
2,319 |
|
Total assets |
|
|
5,468 |
|
|
|
4,518 |
|
|
|
9,986 |
|
|
|
1,875 |
|
|
|
11,861 |
|
Investment in affiliates |
|
|
9 |
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Capital expenditures |
|
|
806 |
|
|
|
352 |
|
|
|
1,158 |
|
|
|
145 |
|
|
|
1,303 |
|
Depreciation and amortization |
|
|
409 |
|
|
|
185 |
|
|
|
594 |
|
|
|
43 |
|
|
|
637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
5,293 |
|
|
$ |
5,135 |
|
|
$ |
10,428 |
|
|
$ |
|
|
|
$ |
10,428 |
|
Equity in income of affiliates |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Segment profit (loss) |
|
|
1,396 |
|
|
|
1,112 |
|
|
|
2,508 |
|
|
|
(251 |
) |
|
|
2,257 |
|
Total assets |
|
|
4,720 |
|
|
|
4,096 |
|
|
|
8,816 |
|
|
|
1,041 |
|
|
|
9,857 |
|
Investment in affiliates |
|
|
9 |
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
Capital expenditures |
|
|
774 |
|
|
|
352 |
|
|
|
1,126 |
|
|
|
1 |
|
|
|
1,127 |
|
Depreciation and amortization |
|
|
335 |
|
|
|
162 |
|
|
|
497 |
|
|
|
24 |
|
|
|
521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
4,660 |
|
|
$ |
4,367 |
|
|
$ |
9,027 |
|
|
$ |
|
|
|
$ |
9,027 |
|
Equity in income of affiliates |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
59 |
|
|
|
60 |
|
Segment profit (loss) |
|
|
1,242 |
|
|
|
942 |
|
|
|
2,184 |
|
|
|
1,553 |
|
|
|
3,737 |
|
Total assets |
|
|
3,989 |
|
|
|
3,596 |
|
|
|
7,585 |
|
|
|
1,121 |
|
|
|
8,706 |
|
Investment in affiliates |
|
|
7 |
|
|
|
13 |
|
|
|
20 |
|
|
|
|
|
|
|
20 |
|
Capital expenditures |
|
|
632 |
|
|
|
280 |
|
|
|
912 |
|
|
|
10 |
|
|
|
922 |
|
Depreciation and amortization |
|
|
275 |
|
|
|
135 |
|
|
|
410 |
|
|
|
24 |
|
|
|
434 |
|
For the years ended December 31, 2008, 2007 and 2006, there were no revenues attributable to
one customer that accounted for more than 10% of total revenues.
The following table presents the details of Corporate and Other segment profit (loss) for
the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Corporate and other expenses |
|
$ |
(240 |
) |
|
$ |
(229 |
) |
|
$ |
(248 |
) |
Interest expense |
|
|
(89 |
) |
|
|
(66 |
) |
|
|
(69 |
) |
Interest and dividend income |
|
|
27 |
|
|
|
44 |
|
|
|
68 |
|
Impairment loss on investments |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
Gain on sale of product line |
|
|
28 |
|
|
|
|
|
|
|
|
|
Litigation settlement |
|
|
(62 |
) |
|
|
|
|
|
|
|
|
Gain on sale of interest in affiliate |
|
|
|
|
|
|
|
|
|
|
1,744 |
|
Equity income from WesternGeco |
|
|
|
|
|
|
|
|
|
|
58 |
|
|
Total |
|
$ |
(361 |
) |
|
$ |
(251 |
) |
|
$ |
1,553 |
|
|
70
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
The following table presents the details of Corporate and Other total assets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
Cash and other assets |
|
$ |
1,684 |
|
|
$ |
795 |
|
|
$ |
903 |
|
Accounts receivable |
|
|
20 |
|
|
|
7 |
|
|
|
9 |
|
Current deferred tax asset |
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
Property, plant and equipment |
|
|
28 |
|
|
|
38 |
|
|
|
66 |
|
Other tangible assets |
|
|
141 |
|
|
|
200 |
|
|
|
141 |
|
|
Total |
|
$ |
1,875 |
|
|
$ |
1,041 |
|
|
$ |
1,121 |
|
|
The following table presents consolidated revenues based on the location of the use of the
products or services for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
United States |
|
$ |
4,512 |
|
|
$ |
3,822 |
|
|
$ |
3,421 |
|
Canada and other |
|
|
666 |
|
|
|
619 |
|
|
|
655 |
|
|
North America |
|
|
5,178 |
|
|
|
4,441 |
|
|
|
4,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Latin America |
|
|
1,127 |
|
|
|
903 |
|
|
|
751 |
|
Europe, Africa, Russia and the Caspian |
|
|
3,386 |
|
|
|
3,076 |
|
|
|
2,489 |
|
Middle East, Asia Pacific |
|
|
2,173 |
|
|
|
2,008 |
|
|
|
1,711 |
|
|
Total |
|
$ |
11,864 |
|
|
$ |
10,428 |
|
|
$ |
9,027 |
|
|
The following table presents net property, plant and equipment based on the location of the
asset at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
|
United States |
|
$ |
1,356 |
|
|
$ |
1,128 |
|
|
$ |
928 |
|
Canada and other |
|
|
104 |
|
|
|
91 |
|
|
|
84 |
|
|
North America |
|
|
1,460 |
|
|
|
1,219 |
|
|
|
1,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Latin America |
|
|
259 |
|
|
|
160 |
|
|
|
111 |
|
Europe, Africa, Russia and the Caspian |
|
|
679 |
|
|
|
641 |
|
|
|
468 |
|
Middle East, Asia Pacific |
|
|
435 |
|
|
|
325 |
|
|
|
210 |
|
|
Total |
|
$ |
2,833 |
|
|
$ |
2,345 |
|
|
$ |
1,801 |
|
|
NOTE 14. EMPLOYEE BENEFIT PLANS
DEFINED BENEFIT PLANS
We have noncontributory defined benefit pension plans (Pension Benefits) covering employees
primarily in the U.S., the U.K. and Germany. Under the provisions of the U.S. qualified pension
plan, a hypothetical cash balance account is established for each participant. Such accounts
receive pay credits on a quarterly basis. The quarterly pay credit is based on a percentage
according to the employees age on the last day of the quarter applied to quarterly eligible
compensation. In addition to quarterly pay credits, a cash balance account receives interest
credits based on the balance in the account on the last day of the quarter. The U.S. qualified
pension plan also includes frozen accrued benefits for participants in legacy defined benefit
plans. For the majority of the participants in the U.K. pension plans, we do not accrue benefits
as the plans are frozen; however, there are a limited number of members who still accrue future
benefits on a defined benefit basis. The Germany pension plan is an unfunded plan where benefits
are based on creditable years of service, creditable pay and accrual rates. We also provide
certain postretirement health care benefits (other postretirement benefits), through an unfunded
plan, to substantially all U.S. employees who retire and have met certain age and service
requirements.
SFAS 158 requires an employer to measure the funded status of each of its plans as of the date
of its year end statement of financial position effective for 2008. The impact of moving our
funded status measurement date from October 1st to December 31st was a
reduction of $4 million to our 2008 beginning retained earnings.
71
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Funded Status
Below is the reconciliation of the beginning and ending balances of benefit obligations, fair
value of plan assets and the funded status of our plans. For our pension plans, the benefit
obligation is the projected benefit obligation (PBO) and for our other post-retirement benefit
plan, the benefit obligation is the accumulated postretirement benefit obligation (APBO). The
beginning of the year balances are as of October 1st for 2008 and 2007. The end of year
balances are as of December 31st for 2008 and September 30th for 2007;
therefore, for 2008 reconciling items reflected below represent fifteen months of activity as a
result of the adoption of SFAS 158.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Benefits |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
280 |
|
|
$ |
270 |
|
|
$ |
319 |
|
|
$ |
361 |
|
|
$ |
156 |
|
|
$ |
157 |
|
Service cost |
|
|
38 |
|
|
|
31 |
|
|
|
3 |
|
|
|
3 |
|
|
|
10 |
|
|
|
8 |
|
Interest cost |
|
|
21 |
|
|
|
16 |
|
|
|
21 |
|
|
|
18 |
|
|
|
11 |
|
|
|
9 |
|
Actuarial (gain) loss |
|
|
(16 |
) |
|
|
(20 |
) |
|
|
(36 |
) |
|
|
(58 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
Benefits paid |
|
|
(16 |
) |
|
|
(13 |
) |
|
|
(8 |
) |
|
|
(16 |
) |
|
|
(18 |
) |
|
|
(14 |
) |
Other |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
(2 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
|
Exchange rate adjustments |
|
|
|
|
|
|
|
|
|
|
(70 |
) |
|
|
10 |
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year |
|
|
303 |
|
|
|
280 |
|
|
|
227 |
|
|
|
319 |
|
|
|
158 |
|
|
|
156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
459 |
|
|
|
410 |
|
|
|
306 |
|
|
|
273 |
|
|
|
|
|
|
|
|
|
Actual return on plan assets |
|
|
(152 |
) |
|
|
62 |
|
|
|
(45 |
) |
|
|
10 |
|
|
|
|
|
|
|
|
|
Employer contributions |
|
|
3 |
|
|
|
2 |
|
|
|
17 |
|
|
|
34 |
|
|
|
18 |
|
|
|
14 |
|
Benefits paid |
|
|
(16 |
) |
|
|
(12 |
) |
|
|
(8 |
) |
|
|
(16 |
) |
|
|
(18 |
) |
|
|
(14 |
) |
Other |
|
|
(4 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange rate adjustments |
|
|
|
|
|
|
|
|
|
|
(73 |
) |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year |
|
|
290 |
|
|
|
459 |
|
|
|
197 |
|
|
|
306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status over (under) at measurement date |
|
|
(13 |
) |
|
|
179 |
|
|
|
(30 |
) |
|
|
(13 |
) |
|
|
(158 |
) |
|
|
(156 |
) |
Employer
contributions – fourth quarter |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
Funded status over (under) at end of year |
|
$ |
(13 |
) |
|
$ |
180 |
|
|
$ |
(30 |
) |
|
$ |
(9 |
) |
|
$ |
(158 |
) |
|
$ |
(152 |
) |
|
The amounts recognized in the consolidated balance sheet consist of the following as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Benefits |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Noncurrent assets |
|
$ |
4 |
|
|
$ |
197 |
|
|
$ |
11 |
|
|
$ |
31 |
|
|
$ |
|
|
|
$ |
|
|
Current liabilities |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(15 |
) |
|
|
(14 |
) |
Noncurrent liabilities |
|
|
(15 |
) |
|
|
(15 |
) |
|
|
(40 |
) |
|
|
(39 |
) |
|
|
(143 |
) |
|
|
(138 |
) |
|
Net amount recognized |
|
$ |
(13 |
) |
|
$ |
180 |
|
|
$ |
(30 |
) |
|
$ |
(9 |
) |
|
$ |
(158 |
) |
|
$ |
(152 |
) |
|
The weighted average asset allocations by asset category for the plans are as follows at
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Plan Assets |
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
Asset Category |
|
Target |
|
2008 |
|
2007 |
|
Target |
|
2008 |
|
2007 |
|
Equity securities |
|
|
68 |
% |
|
|
63 |
% |
|
|
72 |
% |
|
|
53 |
% |
|
|
49 |
% |
|
|
55 |
% |
Debt securities |
|
|
25 |
% |
|
|
30 |
% |
|
|
22 |
% |
|
|
33 |
% |
|
|
36 |
% |
|
|
28 |
% |
Real estate |
|
|
7 |
% |
|
|
6 |
% |
|
|
6 |
% |
|
|
10 |
% |
|
|
10 |
% |
|
|
12 |
% |
Other |
|
|
|
|
|
|
1 |
% |
|
|
|
|
|
|
4 |
% |
|
|
5 |
% |
|
|
5 |
% |
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
72
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
We have investment committees that meet at least quarterly to review the portfolio returns and
periodically to determine asset-mix targets based on asset/liability studies. Third-party
investment consultants assisted us in developing asset allocation strategies to determine our
expected rates of return and expected risk for various investment portfolios. The investment
committees considered these studies in the formal establishment of the current asset-mix targets
based on the projected risk and return levels for all major asset classes.
The accumulated benefit obligation (ABO) is the actuarial present value of pension benefits
attributed to employee service to date and present compensation levels. The ABO differs from the
PBO in that the ABO does not include any assumptions about future compensation levels. The ABO for
all U.S. plans was $293 million and $275 million at December 31, 2008 and 2007, respectively. The
ABO for all non-U.S. plans was $220 million and $309 million at December 31, 2008 and 2007,
respectively.
Information for the plans with ABOs in excess of plan assets is as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Benefits |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Projected benefit obligation |
|
$ |
17 |
|
|
$ |
18 |
|
|
$ |
43 |
|
|
$ |
42 |
|
|
|
n/a |
|
|
|
n/a |
|
Accumulated benefit obligation |
|
|
17 |
|
|
|
18 |
|
|
|
36 |
|
|
|
34 |
|
|
$ |
158 |
|
|
$ |
156 |
|
Fair value of plan assets |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
n/a |
|
|
|
n/a |
|
Weighted average assumptions used to determine benefit obligations for these plans are as
follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Benefits |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Discount rate |
|
|
6.4 |
% |
|
|
6.3 |
% |
|
|
6.4 |
% |
|
|
5.7 |
% |
|
|
6.4 |
% |
|
|
6.3 |
% |
Rate of compensation increase |
|
|
4.0 |
% |
|
|
4.0 |
% |
|
|
4.0 |
% |
|
|
4.1 |
% |
|
|
n/a |
|
|
|
n/a |
|
Social security increase |
|
|
3.5 |
% |
|
|
n/a |
|
|
|
3.1 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
The development of the discount rate for our U.S. plans was based on a bond matching model
whereby a hypothetical bond portfolio of high-quality, fixed-income securities is selected that
will match the cash flows underlying the projected benefit obligation. The discount rate
assumption for our non-U.S. plans reflects the market rate for high-quality, fixed-income
securities.
Accumulated Other Comprehensive Loss
The amounts recognized in accumulated other comprehensive loss consist of the following as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-U.S. Pension |
|
Other Postretirement |
|
|
U.S. Pension Benefits |
|
Benefits |
|
Benefits |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
Net loss (gain) |
|
$ |
173 |
|
|
$ |
(10 |
) |
|
$ |
83 |
|
|
$ |
75 |
|
|
$ |
6 |
|
|
$ |
7 |
|
Net prior service cost |
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
6 |
|
|
Total |
|
$ |
177 |
|
|
$ |
(5 |
) |
|
$ |
83 |
|
|
$ |
75 |
|
|
$ |
10 |
|
|
$ |
13 |
|
|
The estimated net loss and prior service cost for the defined benefit pension plans that will
be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next
fiscal year are $16 million and $1 million, respectively. The estimated prior service cost for the
other postretirement benefits that will be amortized from accumulated other comprehensive loss into
net periodic benefit cost over the next fiscal year is $1 million.
73
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Net Periodic Benefit Costs
The components of net periodic benefit cost are as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Other Postretirement Benefits |
|
|
2008 |
|
2007 |
|
2006 |
|
2008 |
|
2007 |
|
2006 |
|
2008 |
|
2007 |
|
2006 |
|
Service cost |
|
$ |
30 |
|
|
$ |
31 |
|
|
$ |
26 |
|
|
$ |
2 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
8 |
|
|
$ |
8 |
|
|
$ |
7 |
|
Interest cost |
|
|
17 |
|
|
|
16 |
|
|
|
13 |
|
|
|
17 |
|
|
|
18 |
|
|
|
15 |
|
|
|
9 |
|
|
|
9 |
|
|
|
10 |
|
Expected return on plan assets |
|
|
(38 |
) |
|
|
(34 |
) |
|
|
(32 |
) |
|
|
(20 |
) |
|
|
(19 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Amortization of net loss |
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
10 |
|
|
$ |
14 |
|
|
$ |
8 |
|
|
$ |
(2 |
) |
|
$ |
5 |
|
|
$ |
5 |
|
|
$ |
18 |
|
|
$ |
18 |
|
|
$ |
20 |
|
|
Weighted average assumptions used to determine net periodic benefit costs for these plans are
as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Pension Benefits |
|
Non-U.S. Pension Benefits |
|
Other Postretirement Benefits |
|
|
2008 |
|
2007 |
|
2006 |
|
2008 |
|
2007 |
|
2006 |
|
2008 |
|
2007 |
|
2006 |
|
Discount rate |
|
|
6.3 |
% |
|
|
6.0 |
% |
|
|
5.5 |
% |
|
|
5.7 |
% |
|
|
5.0 |
% |
|
|
4.9 |
% |
|
|
6.3 |
% |
|
|
6.0 |
% |
|
|
5.5 |
% |
Expected long-term return on
plan assets |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
7.2 |
% |
|
|
6.9 |
% |
|
|
6.9 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
Rate of compensation increase |
|
|
4.0 |
% |
|
|
4.0 |
% |
|
|
4.0 |
% |
|
|
4.1 |
% |
|
|
3.9 |
% |
|
|
3.5 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
Social security increase |
|
|
3.5 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
3.1 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
In selecting the expected rate of return on plan assets, we consider the average rate of
earnings expected on the funds invested or to be invested to provide for the benefits of these
plans. This includes considering the trusts asset allocation and the expected returns likely to
be earned over the life of the plans.
Expected Cash Flows
For all pension plans, we make annual contributions to the plans in amounts equal to or
greater than amounts necessary to meet minimum governmental funding requirements. We are not
required nor do we intend to make pension contributions to the U.S. qualified pension plan in 2009.
Although we previously expected to forgo contributions for a period of five to eight years, due to
recent downturns in investment markets and the decline in the value of the pension plan assets, we
may be required to make contributions to the U.S. qualified pension plan within the next two to
three years. In 2009, we expect to contribute between $2 million and $3 million to our
nonqualified U.S. pension plans and between $12 million and $14 million to the non-U.S. pension
plans. In 2009, we also expect to make benefit payments related to postretirement welfare plans of
between $15 million and $16 million.
The following table presents the expected benefit payments over the next ten years. The U.S.
and non-U.S. pension benefit payments are made by the respective pension trust funds. The other
postretirement benefits are net of expected Medicare subsidies of approximately $2 million per year
and are payments that are expected to be made by us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
U.S. Pension |
|
Non-U.S. Pension |
|
Postretirement |
Year |
|
Benefits |
|
Benefits |
|
Benefits |
|
2009 |
|
$ |
18 |
|
|
$ |
9 |
|
|
$ |
15 |
|
2010 |
|
|
20 |
|
|
|
7 |
|
|
|
15 |
|
2011 |
|
|
22 |
|
|
|
8 |
|
|
|
16 |
|
2012 |
|
|
26 |
|
|
|
8 |
|
|
|
17 |
|
2013 |
|
|
29 |
|
|
|
9 |
|
|
|
18 |
|
2014-2018 |
|
|
190 |
|
|
|
47 |
|
|
|
102 |
|
74
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts reported for
other postretirement benefits. As of December 31, 2008, the health care cost trend rate was 8% for
employees under age 65 and 6.5% for participants over age 65, with each declining gradually each
successive year until it reaches 5% for both employees under age 65 and over age 65 in 2018. A one
percentage point change in assumed health care cost trend rates would have had the following
effects on 2008:
|
|
|
|
|
|
|
|
|
|
|
One Percentage |
|
One Percentage |
|
|
Point Increase |
|
Point Decrease |
|
Effect on total of service and interest cost components |
|
$ |
0.4 |
|
|
$ |
(0.4 |
) |
Effect on postretirement welfare benefit obligation |
|
|
6.1 |
|
|
|
(5.6 |
) |
DEFINED CONTRIBUTION PLANS
During the periods reported, generally all of our U.S. employees were eligible to participate
in our sponsored Thrift Plan, which is a 401(k) plan under the Internal Revenue Code of 1986, as
amended (the Code). The Thrift Plan allows eligible employees to elect to contribute from 1% to
50% of their salaries to an investment trust. Beginning January 1, 2007, employee contributions
are matched by the Company in cash at the rate of $1.00 per $1.00 employee contribution for the
first 5% of the employees salary. In prior years, employee contributions were matched in cash by
us at the rate of $1.00 per $1.00 employee contribution for the first 3% and $0.50 per $1.00
employee contribution for the next 2% of the employees salary. In all years, such contributions
vest immediately. In addition, we make cash contributions for all eligible employees between 2%
and 5% of their salary depending on the employees age. Such contributions are fully vested to the
employee after three years of employment. The Thrift Plan provides for ten different investment
options, for which the employee has sole discretion in determining how both the employer and
employee contributions are invested. The Thrift Plan does not offer Baker Hughes company stock as
an investment option. Our contributions to the Thrift Plan and several other non-U.S. defined
contribution plans amounted to $137 million, $131 million and $102 million in 2008, 2007 and 2006,
respectively.
For certain non-U.S. employees who are not eligible to participate in the Thrift Plan, we
provide a non-qualified defined contribution plan that provides basically the same benefits as the
Thrift Plan. In addition, we provide a non-qualified supplemental retirement plan (SRP) for
certain officers and employees whose benefits under the Thrift Plan and/or the U.S. defined benefit
pension plan are limited by federal tax law. The SRP also allows the eligible employees to defer a
portion of their eligible compensation and provides for employer matching and base contributions
pursuant to limitations. Both non-qualified plans are invested through trusts, and the assets and
corresponding liabilities are included in our consolidated balance sheet. Our contributions to
these non-qualified plans were $9 million, $11 million and $8 million for 2008, 2007 and 2006,
respectively.
In 2009, we estimate we will contribute between $139 million and $150 million to our defined
contribution plans.
POSTEMPLOYMENT BENEFITS
We provide certain postemployment disability income, medical and other benefits to
substantially all qualifying former or inactive U.S. employees. Income benefits for long-term
disability are provided through a fully-insured plan. The continuation of medical and other
benefits while on disability (Continuation Benefits) are provided through a qualified
self-insured plan. The accrued postemployment liability for Continuation Benefits at
December 31, 2008 and 2007 was $12 million and $14 million, respectively, and is included in other
liabilities in our consolidated balance sheet.
NOTE 15. COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2008, we had long-term non-cancelable operating leases covering certain
facilities and equipment. The minimum annual rental commitments, net of amounts due under
subleases, for each of the five years in the period ending December 31, 2013 are $123 million, $94
million, $67 million, $47 million and $27 million, respectively, and $118 million in the aggregate
thereafter. Rent expense, which generally includes transportation equipment and warehouse
facilities, was $227 million, $179 million and $161 million for the years ended December 31, 2008,
2007 and 2006, respectively. We have not entered into any significant capital leases during the
three years ended December 31, 2008.
75
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Litigation
We are involved in litigation or proceedings that have arisen in our ordinary business
activities. We insure against these risks to the extent deemed prudent by our management and to
the extent insurance is available, but no assurance can be given that the nature and amount of that
insurance will be sufficient to fully indemnify us against liabilities arising out of pending and
future legal proceedings. Many of these insurance policies contain deductibles or self-insured
retentions in amounts we deem prudent and for which we are responsible for payment. In determining
the amount of self-insurance, it is our policy to self-insure those losses that are predictable,
measurable and recurring in nature, such as claims for automobile liability, general liability and
workers compensation. We record accruals for the uninsured portion of losses. The accruals for
losses are calculated by estimating losses for claims using historical claim data, specific loss
development factors and other information as necessary.
On September 12, 2001, we, without admitting or denying the factual allegations contained in
the Order, consented with the SEC to the entry of an Order making Findings and Imposing a
Cease-and-Desist Order (the Order) for violations of Section 13(b)(2)(A) and Section 13(b)(2)(B)
of the Exchange Act. Among the findings included in the Order were the following: In 1999, we
discovered that certain of our officers had authorized an improper $75,000 payment to an Indonesian
tax official, after which we embarked on a corrective course of conduct, including voluntarily and
promptly disclosing the misconduct to the SEC and the DOJ. In the course of our investigation of
the Indonesia matter, we learned that we had made payments in the amount of $15,000 and $10,000 in
India and Brazil, respectively, to our agents, without taking adequate steps to ensure that none of
the payments would be passed on to foreign government officials. The Order found that the
foregoing payments violated Section 13(b)(2)(A). The Order also found us in violation of Section
13(b)(2)(B) because we did not have a system of internal controls to determine if payments violated
the FCPA. The FCPA makes it unlawful for U.S. issuers, including us, or anyone acting on their
behalf, to make improper payments to any foreign official in order to obtain or retain business.
In addition, as discussed below, the FCPA establishes accounting and internal control requirements
for U.S. issuers. We cooperated with the SECs investigation.
By the Order, dated September 12, 2001 (previously disclosed by us and incorporated by
reference in this annual report as Exhibit 99.1), we agreed to cease and desist from committing or
causing any violation and any future violation of Section 13(b)(2)(A) and Section 13(b)(2)(B) of
the Exchange Act. Such Sections of the Exchange Act require issuers to: (x) make and keep books,
records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions
and dispositions of the assets of the issuer and (y) devise and maintain a system of internal
accounting controls sufficient to provide reasonable assurances that: (i) transactions are
executed in accordance with managements general or specific authorization; and (ii) transactions
are recorded as necessary: (I) to permit preparation of financial statements in conformity with
generally accepted accounting principles or any other criteria applicable to such statements, and
(II) to maintain accountability for assets.
On March 29, 2002, we announced that we had been advised that the SEC and the DOJ were
conducting investigations into allegations of violations of law relating to Nigeria and other
related matters. The SEC issued a formal order of investigation into possible violations of
provisions under the FCPA regarding anti-bribery, books and records and internal controls. In
connection with the investigations, the SEC issued subpoenas seeking information about our
operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003
and April 22, 2005) as part of its investigation. We provided documents to and cooperated fully
with the SEC and DOJ. In addition, we conducted internal investigations into these matters. Our
internal investigations identified issues regarding the propriety of certain payments and apparent
deficiencies in our books and records and internal controls with respect to certain operations in
Angola, Kazakhstan and Nigeria, as well as potential liabilities to government authorities in
Nigeria. Evidence obtained during the course of the investigations was provided to the SEC and
DOJ.
On April 26, 2007, the United States District Court, Southern District of Texas, Houston
Division (the Court) unsealed a three-count criminal information that had been filed against us
as part of the execution of a Deferred Prosecution Agreement (the DPA) between us and the DOJ.
The three counts arise out of payments made to an agent in connection with a project in Kazakhstan
and include conspiracy to violate the FCPA, a substantive violation of the antibribery provisions
of the FCPA, and a violation of the FCPAs books-and-records provisions. All three counts relate
to our operations in Kazakhstan during the period from 2000 to 2003.
Although we did not plead guilty to that information, we face prosecution under that information,
and possibly under other charges as well, if we fail to comply with the terms of the DPA. Those
terms include, for the two-year term of the DPA, full cooperation with the government; compliance
with all federal criminal law, including but not limited to the FCPA; and adoption of a Compliance
Code containing specific provisions intended to prevent violations of the FCPA. The DPA also
requires us to retain an independent monitor for a term of three years to assess and make
recommendations about our compliance policies and procedures and our implementation of those
procedures. Provided that we comply with the DPA, the DOJ has agreed not to prosecute us for
violations of the FCPA based on information that we have disclosed to the DOJ regarding our
operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and
Azerbaijan, among other countries.
76
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
On the same date, the Court also accepted a plea of guilty by our subsidiary Baker Hughes
Services International, Inc. (BHSII) pursuant to a plea agreement between BHSII and the DOJ (the
Plea Agreement) based on similar charges relating to the same conduct. Pursuant to the Plea
Agreement, BHSII agreed to a three-year term of organizational probation. The Plea Agreement
contains provisions requiring BHSII to cooperate with the government, to comply with all federal
criminal law, and to adopt a Compliance Code similar to the one that the DPA requires of the
Company.
Also on April 26, 2007, the SEC filed a Complaint (the SEC Complaint) and a proposed order
(the SEC Order) against us in the Court. The SEC Complaint and the SEC Order were filed as part
of a settled civil enforcement action by the SEC, to resolve the civil portion of the governments
investigation of us. As part of our agreement with the SEC, we consented to the filing of the SEC
Complaint without admitting or denying the allegations in the Complaint, and also consented to the
entry of the SEC Order. The SEC Complaint alleges civil violations of the FCPAs antibribery
provisions related to our operations in Kazakhstan, the FCPAs books-and-records and
internal-controls provisions related to our operations in Nigeria, Angola, Kazakhstan, Indonesia,
Russia, and Uzbekistan, and the SECs cease and desist order of September 12, 2001. The SEC Order
became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order
enjoins us from violating the FCPAs antibribery, books-and-records, and internal-controls
provisions. As in the DPA, it requires that we retain the independent monitor to assess our FCPA
compliance policies and procedures for the three-year period.
Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid, in
the second quarter of 2007, $44 million ($11 million in criminal penalties, $10 million in civil
penalties, $20 million in disgorgement of profits and $3 million in pre-judgment interest) to
settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the
potential settlement. We previously disclosed copies of these agreements and settlements and the
same are incorporated by reference in this annual report as Exhibits 10.57, 10.58 and 99.2 through
99.7.
We have retained, and the SEC and DOJ have approved, an independent monitor to assess our FCPA
compliance policies and procedures for the specified three-year period.
On May 4, 2007 and May 15, 2007, The Sheetmetal Workers National Pension Fund and Chris
Larson, respectively, instituted shareholder derivative lawsuits for and on the Companys behalf
against certain current and former members of the Board of Directors and certain current and former
officers, and the Company as a nominal defendant, following the Companys settlement with the DOJ
and SEC in April 2007. On August 17, 2007, the Alaska Plumbing and Pipefitting Industry Pension
Trust also instituted a shareholder derivative lawsuit for and on the Companys behalf against
certain current and former members of the Board of Directors and certain current and former
officers, and the Company as a nominal defendant. On June 6, 2008, the Midwestern Teamsters
Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft Mbh instituted a shareholder derivative
lawsuit for and on the Companys behalf against certain current and former members of the Board of
Directors and certain current and former officers, and the Company as a nominal defendant. The
complaints in all four lawsuits allege, among other things, that the individual defendants failed
to implement adequate controls and compliance procedures to prevent the events addressed by the
settlement with the DOJ and SEC. The relief sought in the lawsuits includes a declaration that the
defendants breached their fiduciary duties, an award of damages sustained by the Company as a
result of the alleged breach and monetary and injunctive relief, as well as attorneys and experts
fees. On May 15, 2008, the consolidated complaint of the Sheetmetal Workers National Pension Fund
and The Alaska Plumbing and Pipefitting Industry Pension Trust was dismissed for lack of subject
matter jurisdiction by the Houston Division of the United States District Court for the Southern
District of Texas. The lawsuit brought by Chris Larson in the 215th District Court of Harris
County, Texas was dismissed on September 15, 2008. The lawsuit brought by the Midwestern Teamsters
Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft Mbh is pending in the Houston Division
of the United States District Court for the Southern District of Texas. An estimate of the
possible loss or range of loss in connection with this lawsuit cannot be made. However, we do not
expect this lawsuit to have a material adverse effect on our consolidated financial statements.
On May 12, 2006, Baker Hughes Oilfield Operations, Inc. (BHOO), a subsidiary of the Company, was
named as a defendant in a lawsuit in the United States District Court, Eastern District of Texas
brought by ReedHycalog against BHOO and other third parties arising out of alleged patent
infringement relating to the sale of certain diamond drill bits utilizing certain types of
polycrystalline diamond cutters sold by our Hughes Christensen division (the ReedHycalog Claims).
On May 22, 2008, an agreement was reached for reciprocal licenses with ReedHycalog, now a division
of National Oilwell Varco, Inc. regarding the ReedHycalog Claims and related Baker Hughes
counter-claims. As part of the agreement, the Company and ReedHycalog agreed to a cross-license of
the disputed technologies. As a result, in June 2008, the Company paid ReedHycalog $70 million in
royalties for prior use of certain patented technologies, and ReedHycalog paid the Company $8
million in royalties for the license of certain Company patented technologies. The net pre-tax
charge of $62 million for the settlement of this litigation is reflected in the consolidated
statement of operations for the year ended December 31, 2008. In addition, the Company will pay a
minimum of $30 million in royalties for future
77
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
use, of which $7 million has been paid as of December 31, 2008. Pursuant to the agreement, BHOO
was dismissed from all claims and has released ReedHycalog from all counter-claims.
Further information is contained in the Environmental Matters section of Item 1. Business
contained herein.
Environmental Matters
Our past and present operations include activities which are subject to extensive domestic
(including U.S. federal, state and local) and international environmental regulations with regard
to air, land and water quality and other environmental matters. Our environmental procedures,
policies and practices are designed to ensure compliance with existing laws and regulations and to
minimize the possibility of significant environmental damage.
We are involved in voluntary remediation projects at some of our present and former
manufacturing locations or other facilities, the majority of which relate to properties obtained in
acquisitions or to sites no longer actively used in operations. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order.
Remediation costs are accrued based on estimates of probable exposure using currently available
facts, existing environmental permits, technology and presently enacted laws and regulations.
Remediation cost estimates include direct costs related to the environmental investigation,
external consulting activities, governmental oversight fees, treatment equipment and costs
associated with long-term operation, maintenance and monitoring of a remediation project.
We have also been identified as a potentially responsible party (PRP) in remedial activities
related to various Superfund sites. We participate in the process set out in the Joint
Participation and Defense Agreement to negotiate with government agencies, identify other PRPs,
determine each PRPs allocation and estimate remediation costs. We have accrued what we believe to
be our pro-rata share of the total estimated cost of remediation and associated management of these
Superfund sites. This share is based upon the ratio that the estimated volume of waste we
contributed to the site bears to the total estimated volume of waste disposed at the site.
Applicable United States federal law imposes joint and several liability on each PRP for the
cleanup of these sites leaving us with the uncertainty that we may be responsible for the
remediation cost attributable to other PRPs who are unable to pay their share. No accrual has been
made under the joint and several liability concept for those Superfund sites where our
participation is de minimis since we believe that the probability that we will have to pay material
costs above our volumetric share is remote. We believe there are other PRPs who have greater
involvement on a volumetric calculation basis, who have substantial assets and who may be
reasonably expected to pay their share of the cost of remediation. For those Superfund sites where
we are a significant PRP, remediation costs are estimated to include recalcitrant parties. In some
cases, we have insurance coverage or contractual indemnities from third parties to cover a portion
of or the ultimate liability.
Our total accrual for environmental remediation is $17 million and $17 million, which includes
accruals of $6 million and $5 million for the various Superfund sites, at December 31, 2008 and
2007, respectively. The determination of the required accruals for remediation costs is subject to
uncertainty, including the evolving nature of environmental regulations and the difficulty in
estimating the extent and type of remediation activity that will be utilized. We believe that the
likelihood of material losses in excess of the amounts accrued is remote.
Other
In the normal course of business with customers, vendors and others, we have entered into
off-balance sheet arrangements, such as letters of credit and other bank issued guarantees, which
totaled approximately $660 million at December 31, 2008. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts of approximately $433 million at December 31, 2008. It is not practicable to estimate
the fair value of these financial instruments. None of the off-balance sheet arrangements either
has, or is likely to have, a material effect on our consolidated financial statements.
78
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 16. ACCUMULATED OTHER COMPREHENSIVE LOSS
The following is a reconciliation of Accumulated Other Comprehensive Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pensions and |
|
Foreign |
|
Accumulated |
|
|
Other |
|
Currency |
|
Other |
|
|
Postretirement |
|
Translation |
|
Comprehensive |
|
|
Benefits |
|
Adjustments |
|
Loss |
|
Balance at December 31, 2006 |
|
$ |
(127 |
) |
|
$ |
(60 |
) |
|
$ |
(187 |
) |
Translation adjustments |
|
|
|
|
|
|
72 |
|
|
|
72 |
|
Amortization of prior service cost |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Amortization of actuarial net loss |
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Actuarial net gains arising in the year |
|
|
106 |
|
|
|
|
|
|
|
106 |
|
Effect of exchange rate |
|
|
(3 |
) |
|
|
|
|
|
|
(3 |
) |
Deferred taxes |
|
|
(37 |
) |
|
|
|
|
|
|
(37 |
) |
|
Balance at December 31, 2007 |
|
|
(56 |
) |
|
|
12 |
|
|
|
(44 |
) |
Translation adjustments |
|
|
|
|
|
|
(354 |
) |
|
|
(354 |
) |
Amortization of prior service cost |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Amortization of actuarial net loss |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Actuarial net losses arising in the year |
|
|
(222 |
) |
|
|
|
|
|
|
(222 |
) |
Adjustment to reflect change in measurement date |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Effect of exchange rate |
|
|
26 |
|
|
|
|
|
|
|
26 |
|
Deferred taxes |
|
|
67 |
|
|
|
|
|
|
|
67 |
|
|
Balance at December 31, 2008 |
|
$ |
(181 |
) |
|
$ |
(342 |
) |
|
$ |
(523 |
) |
|
79
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 17. QUARTERLY DATA (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
Total |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Year |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
2,670 |
|
|
$ |
2,998 |
|
|
$ |
3,010 |
|
|
$ |
3,186 |
|
|
$ |
11,864 |
|
Gross profit (1) |
|
|
798 |
|
|
|
895 |
|
|
|
879 |
|
|
|
912 |
|
|
|
3,484 |
|
Income from continuing operations |
|
|
569 |
|
|
|
551 |
|
|
|
590 |
|
|
|
609 |
|
|
|
2,319 |
|
Net income |
|
|
395 |
|
|
|
379 |
|
|
|
429 |
|
|
|
432 |
|
|
|
1,635 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
1.28 |
|
|
|
1.24 |
|
|
|
1.40 |
|
|
|
1.41 |
|
|
|
5.32 |
|
Net income |
|
|
1.28 |
|
|
|
1.24 |
|
|
|
1.40 |
|
|
|
1.41 |
|
|
|
5.32 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
1.27 |
|
|
|
1.23 |
|
|
|
1.39 |
|
|
|
1.41 |
|
|
|
5.30 |
|
Net income |
|
|
1.27 |
|
|
|
1.23 |
|
|
|
1.39 |
|
|
|
1.41 |
|
|
|
5.30 |
|
Dividends per share |
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.15 |
|
|
|
0.15 |
|
|
|
0.56 |
|
Common stock market prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
81.34 |
|
|
|
89.56 |
|
|
|
88.57 |
|
|
|
60.54 |
|
|
|
|
|
Low |
|
|
63.90 |
|
|
|
68.50 |
|
|
|
60.93 |
|
|
|
26.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
2,473 |
|
|
$ |
2,537 |
|
|
$ |
2,678 |
|
|
$ |
2,740 |
|
|
$ |
10,428 |
|
Gross profit (1) |
|
|
781 |
|
|
|
773 |
|
|
|
818 |
|
|
|
839 |
|
|
|
3,211 |
|
Income from continuing operations |
|
|
555 |
|
|
|
532 |
|
|
|
576 |
|
|
|
594 |
|
|
|
2,257 |
|
Net income |
|
|
375 |
|
|
|
349 |
|
|
|
389 |
|
|
|
401 |
|
|
|
1,514 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
1.17 |
|
|
|
1.10 |
|
|
|
1.23 |
|
|
|
1.27 |
|
|
|
4.76 |
|
Net income |
|
|
1.17 |
|
|
|
1.10 |
|
|
|
1.23 |
|
|
|
1.27 |
|
|
|
4.76 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
1.17 |
|
|
|
1.09 |
|
|
|
1.22 |
|
|
|
1.26 |
|
|
|
4.73 |
|
Net income |
|
|
1.17 |
|
|
|
1.09 |
|
|
|
1.22 |
|
|
|
1.26 |
|
|
|
4.73 |
|
Dividends per share |
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.52 |
|
Common stock market prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
71.94 |
|
|
|
89.36 |
|
|
|
90.73 |
|
|
|
98.67 |
|
|
|
|
|
Low |
|
|
62.74 |
|
|
|
66.73 |
|
|
|
75.84 |
|
|
|
78.23 |
|
|
|
|
|
|
|
|
(1) |
|
Represents revenues less cost of sales, cost of services and rentals and research
and engineering. |
80
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this annual report, we have evaluated the effectiveness
of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of
the Exchange Act of 1934, as amended (the Exchange Act). This evaluation was carried out under
the supervision and with the participation of our management, including our principal executive
officer and principal financial officer. Based on this evaluation, these officers have concluded
that, as of December 31, 2008, our disclosure controls and procedures, as defined by Rule 13a-15(e)
of the Exchange Act, are effective at a reasonable assurance level.
Disclosure controls and procedures are our controls and other procedures that are designed to
ensure that information required to be disclosed by us in the reports that we file or submit under
the Exchange Act, such as this annual report, is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that information required
to be disclosed by us in the reports that we file under the Exchange Act is accumulated and
communicated to our management, including our principal executive officer and principal financial
officer, as appropriate, to allow timely decisions regarding required disclosure.
Design and Evaluation of Internal Control Over Financial Reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of
their assessment of the design and effectiveness of our internal controls over financial reporting
as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2008. Deloitte &
Touche LLP, the Companys independent registered public accounting firm, has issued an attestation
report on the effectiveness of the Companys internal control over financial reporting.
Managements report and the independent registered public accounting firms attestation report are
included in Item 8 under the caption entitled Managements Report on Internal Control Over
Financial Reporting and Report of Independent Registered Public Accounting Firm and are
incorporated herein by reference.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter
ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Item 5.03(a). Amendments to Articles of Incorporation or Bylaws; Changes in Fiscal Year.
On February 26, 2009, the Board of Directors amended Article III, Section 1 of the Companys
Bylaws to decrease the authorized number of directors from twelve to eleven, effective
April 23, 2009, which will eliminate the vacancy on the Board of Directors that will result from
the retirement of General James F. McCall as a director of the Company following the Companys 2009
annual meeting of stockholders. Because this Annual Report on Form 10-K is being filed within four
business days from February 26, 2009, the restatement of the Bylaws is being disclosed hereunder
rather than under Item 5.03(a) of Form 8-K. The restated Bylaws are attached hereto and
incorporated by reference as Exhibits 3.2 and 4.3.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates
for our principal executive officer, principal financial officer and principal accounting officer
are described in Item 1. Business of this Annual Report. Information concerning our directors is
set forth in the sections entitled Proposal No. 1, Election of Directors, and Corporate
Governance – Committees of the Board – Audit/Ethics Committee in our Proxy Statement for the
Annual Meeting of Stockholders to be held April 23, 2009 (Proxy Statement), which sections are
incorporated herein by reference. For information regarding our executive officers, see Item 1.
Business – Executive Officers in this Annual Report on Form 10-K. Additional information
regarding
81
compliance by directors and executive officers with Section 16(a) of the Exchange Act is set
forth under the section entitled Compliance with Section 16(a) of the Securities Exchange Act of
1934 in our Proxy Statement, which section is incorporated herein by reference. For information
concerning our Business Code of Conduct and Code of Ethical Conduct Certificates, see Item 1.
Business in this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information for this item is set forth in the following sections of our Proxy Statement, which
sections are incorporated herein by reference: Compensation Discussion and Analysis, Executive
Compensation, Director Compensation, Compensation Committee Interlocks and Insider
Participation and Compensation Committee Report.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Information concerning security ownership of certain beneficial owners and our management is
set forth in the sections entitled Voting Securities and Security Ownership of Management in
our Proxy Statement, which sections are incorporated herein by reference.
Our Board of Directors has approved procedures for use under our Securities Trading and
Disclosure Policy to permit our employees, officers and directors to enter into written trading
plans complying with Rule 10b5-1 under the Exchange Act. Rule 10b5-1 provides criteria under which such an individual may establish a prearranged plan to buy or
sell a specified number of shares of a companys stock over a set period of time. Any such plan
must be entered into in good faith at a time when the individual is not in possession of material,
nonpublic information. If an individual establishes a plan satisfying the requirements of Rule
10b5-1, such individuals subsequent receipt of material, nonpublic information will not prevent
transactions under the plan from being executed. Certain of our officers have advised us that they
have and may enter into a stock sales plan for the sale of shares of our common stock which are
intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the
Company has and may in the future enter into repurchases of our common stock under a plan that
complies with Rule 10b5-1 or Rule 10b-18 of the Exchange Act.
Equity Compensation Plan Information
The information in the following table is presented as of December 31, 2008 with respect to
shares of our common stock that may be issued under our existing equity compensation plans,
including the Baker Hughes Incorporated 1993 Stock Option Plan, the Baker Hughes Incorporated
Long-Term Incentive Plan and the Baker Hughes Incorporated 2002 Directors & Officers Long-Term
Incentive Plan, all of which have been approved by our stockholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions of shares) |
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
Number of |
|
|
|
|
|
Remaining Available |
|
|
Securities to be |
|
|
|
|
|
for Future Issuance |
|
|
Issued Upon |
|
Weighted Average |
|
Under Equity |
|
|
Exercise of |
|
Exercise Price of |
|
Compensation Plans |
|
|
Outstanding |
|
Outstanding |
|
(excluding securities |
Equity Compensation Plan |
|
Options, Warrants |
|
Options, Warrants |
|
reflected in the first |
Category |
|
and Rights |
|
and Rights |
|
column) |
|
Stockholder-approved plans (excluding
Employee Stock Purchase Plan) |
|
|
1.3 |
|
|
$ |
64.30 |
|
|
|
2.5 |
|
Nonstockholder-approved plans (1) |
|
|
2.2 |
|
|
|
57.36 |
|
|
|
3.2 |
|
|
Subtotal (except for weighted average
exercise price) |
|
|
3.5 |
|
|
|
59.96 |
|
|
|
5.7 |
|
Employee Stock Purchase Plan (2) |
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
Total |
|
|
3.5 |
|
|
$ |
59.96 |
|
|
|
6.7 |
|
|
|
|
|
(1) |
|
The table includes the following nonstockholder-approved plans: the 1998 Employee
Stock Option Plan, the 2002 Employee Long-Term Incentive Plan and the Director Compensation
Deferral Plan. A description of each of these plans is set forth below. |
|
(2) |
|
The per share purchase price under the Baker Hughes Incorporated Employee Stock
Purchase Plan is determined in accordance |
82
|
|
|
|
|
with section 423 of the Code as 85% of the lower of the fair market value of a share of our
common stock on the date of grant or the date of purchase. |
Our nonstockholder-approved plans are described below:
1998 Employee Stock Option Plan
The Baker Hughes Incorporated 1998 Employee Stock Option Plan (the 1998 ESOP) was adopted
effective as of October 1, 1998. The number of shares authorized for issuance under the 1998 ESOP
was 7.0 million shares. Nonqualified stock options may be granted under the 1998 ESOP to our
employees. The exercise price of the options will be equal to the fair market value per share of
our common stock on the date of grant, and option terms may be up to ten years. Under the terms
and conditions of the option award agreements for options issued under the 1998 ESOP, options
generally vest and become exercisable in installments over the optionees period of service, and
the options vest on an accelerated basis in the event of a change in control. As of
December 31, 2008, options covering approximately 0.1 million shares of our common stock were
outstanding under the 1998 ESOP, options covering approximately 66,000 shares were exercised during
fiscal year 2008. There are no shares available for grants of future options as the plan expired
on October 1, 2008.
2002 Employee Long-Term Incentive Plan
The Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (the 2002 Employee
LTIP) was adopted effective as of March 6, 2002. The 2002 Employee LTIP permits the grant of
awards as nonqualified stock options, stock appreciation rights, restricted stock, restricted stock
units, performance shares, performance units, stock awards and cash-based awards to our corporate
officers and key employees. The number of shares authorized for issuance under the 2002 Employee
LTIP is 9.5 million, with no more than 2.7 million available for grant as awards other than options
(the number of shares is subject to adjustment for changes in our common stock).
The 2002 Employee LTIP is the companion plan to the Baker Hughes Incorporated 2002 Director &
Officer Long-Term Incentive Plan, which was approved by our stockholders in 2002. The rationale
for the two companion plans was to discontinue the use of the remaining older option plans and to
have only two plans from which we would issue compensation awards.
Options. The exercise price of the options will not be less than the fair market value of the
shares of our common stock on the date of grant, and options terms may be up to ten years. The
maximum number of shares of our common stock that may be subject to options granted under the 2002
Employee LTIP to any one employee during any one fiscal year will not exceed 3.0 million, subject
to adjustment under the antidilution provisions of the 2002 Employee LTIP. Under the terms and
conditions of the stock option awards for options issued under the 2002 Employee LTIP, options
generally vest and become exercisable in installments over the optionees period of service, and
the options vest on an accelerated basis in the event of a change in control or certain
terminations of employment. As of December 31, 2008, options covering approximately 2.0 million
shares of our common stock were outstanding under the 2002 Employee LTIP, options covering
approximately 0.2 million shares were exercised during fiscal year 2008 and approximately 2.7
million shares remained available for future options.
Performance Shares and Units; Cash-Based Awards. Performance shares may be granted to
employees in the amounts and upon the terms determined by the Compensation Committee of our Board
of Directors, but must be limited to no more than 1.0 million shares to any one employee in any one
fiscal year. Performance units and cash-based awards may be granted to employees in amounts and
upon the terms determined by the Compensation Committee, but must be limited to no more than $10
million for any one employee in any one fiscal year. The performance measures that may be used to
determine the extent of the actual performance payout or vesting include, but are not limited to,
net earnings; earnings per share; return measures; cash flow return on investments (net cash flows
divided by owners equity); earnings before or after taxes, interest, depreciation and/or
amortization; share price (including growth measures and total shareholder return) and Baker Value
Added (our metric that measures operating profit after tax less the cost of capital employed).
Restricted Stock and Restricted Stock Units. With respect to awards of restricted stock and
restricted stock units, the Compensation Committee will determine the conditions or restrictions on
the awards, including whether the holders of the restricted stock or restricted stock units will
exercise full voting rights (in the case of restricted stock awards only) or receive dividends and
other distributions during the restriction period. At the time the award is made, the Compensation
Committee will determine the right to receive unvested restricted stock or restricted units after
termination of service. Awards of restricted stock are limited to 1.0 million shares in any one
year to any one individual. Awards of restricted stock units are limited to 1.0 million units in
any one year to any one individual.
83
Stock Appreciation Rights. Stock appreciation rights may be granted under the 2002 Employee
LTIP on the terms and conditions determined by the Compensation Committee. The grant price of a
freestanding stock appreciation right will not be less than the fair market value of our common
stock on the date of grant. The maximum number of shares of our common stock that may be subject
to stock appreciation rights granted under the 2002 Employee LTIP to any one individual during any
one fiscal year will not exceed 3.0 million shares, subject to adjustment under the antidilution
provisions of the 2002 Employee LTIP.
Administration; Amendment and Termination. The Compensation Committee shall administer the
2002 Employee LTIP, and in the absence of the Compensation Committee, the Board will administer the
Plan. The Compensation Committee will have full and exclusive power to interpret the provisions of
the 2002 Employee LTIP as the Committee may deem necessary or proper. The Board may alter, amend,
modify, suspend or terminate the 2002 Employee LTIP, except that no amendment, modification,
suspension or termination that would adversely affect in any material way the rights of a
participant under any award previously granted under the 2002 Employee LTIP may be made without the
written consent of the participant. In addition, no amendment of the 2002 Employee LTIP shall
become effective absent stockholder approval of the amendment, to the extent stockholder approval
is otherwise required by applicable legal requirements.
Director Compensation Deferral Plan
The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated
effective July 24, 2002 (the Deferral Plan), is intended to provide a means for members of our
Board of Directors to defer compensation otherwise payable and provide flexibility with respect to
our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer
income with respect to each calendar year. The compensation deferrals may be stock option-related
deferrals or cash-based deferrals. If a director elects a stock option-related deferral, on the
last day of each calendar quarter he or she will be granted a nonqualified stock option. The
number of shares subject to the stock option is calculated by multiplying the amount of the
deferred compensation that otherwise would have been paid to the director during the quarter by 4.4
and then dividing by the fair market value of our common stock on the last day of the quarter. The
per share exercise price of the option will be the fair market value of a share of our common stock
on the date the option is granted. Stock options granted under the Deferral Plan vest on the first
anniversary of the date of grant and must be exercised within ten years of the date of grant. If a
directors directorship terminates for any reason, any options outstanding will expire three years
after the termination of the directorship. The maximum aggregate number of shares of our common
stock that may be issued under the Deferral Plan is 0.5 million. As of December 31, 2008, options
covering 3,313 shares of our common stock were outstanding under the Deferral Plan, there were no
shares exercised during fiscal 2008 and approximately 0.5 million shares remained available for
future options.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information for this item is set forth in the sections entitled Corporate Governance-Director
Independence and Certain Relationships and Related Transactions in our Proxy Statement, which
sections are incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accounting fees and services is set forth in the section
entitled Fees Paid to Deloitte & Touche LLP in our Proxy Statement, which section is incorporated
herein by reference.
PART IV
ITEM
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) |
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List of Documents filed as part of this Report. |
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(1) |
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Financial Statements |
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All financial statements of the Registrant as set forth under Item 8 of this Annual Report on
Form 10-K. |
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(2) |
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Financial Statement Schedules |
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Schedule II Valuation and Qualifying Accounts |
84
(3) Exhibits
Each exhibit identified below is filed as a part of this report. Exhibits designated with an
* are filed as an exhibit to this Annual Report on Form 10-K. Exhibits designated with a
+ are identified as management contracts or compensatory plans or arrangements. Exhibits
previously filed as indicated below are incorporated by reference.
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3.1 |
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Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
June 30, 2007). |
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3.2* |
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Restated Bylaws of Baker Hughes Incorporated effective as of April 23, 2009. |
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3.3 |
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Bylaws of Baker Hughes Incorporated restated as of October 23, 2008 and
effective until April 23, 2009 (filed as Exhibit 3.2 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended
September 30, 2008). |
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4.1 |
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Rights of Holders of the Companys Long-Term Debt. The Company has no
long-term debt instrument with regard to which the securities authorized
there under equal or exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. The Company agrees to furnish a copy
of its long-term debt instruments to the SEC upon request. |
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4.2 |
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Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
June 30, 2007). |
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4.3* |
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Restated Bylaws of Baker Hughes Incorporated effective as of April 23, 2009
(filed as Exhibit 3.2 to this Annual Report on Form 10-K). |
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4.4 |
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Bylaws of Baker Hughes Incorporated restated as of October 23, 2008 and
effective until April 23, 2009 (filed as Exhibit 3.2 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended
September 30, 2008). |
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4.5 |
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Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank
of New York, Trustee, providing for the issuance of securities in series
(filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form
10-K for the year ended December 31, 2004). |
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4.6 |
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Indenture dated October 28, 2008, between Baker Hughes Incorporated and The
Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit
4.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed
October 29, 2008). |
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4.7 |
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Officers Certificate of Baker Hughes Incorporated dated October 28 2008
establishing the 6.50% Senior Notes due 2013 and the 7.50% Senior Notes due
2018 (filed as Exhibit 4.2 to Current Report of Baker Hughes Incorporated
on Form 8-K filed October 29, 2008). |
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4.8 |
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Form of 6.50% Senior Notes Due 2013 (filed as Exhibit 4.3 to Current Report
of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). |
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4.9 |
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Form of 7.50% Senior Notes Due 2018 (filed as Exhibit 4.4 to Current Report
of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). |
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10.1+ |
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Amendment and Restatement of Employment Agreement between Chad C. Deaton
and Baker Hughes Incorporated dated as of January 1, 2009 (filed as Exhibit
10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed
December 19, 2008). |
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10.2+ |
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Form of Amended and Restated Change in Control Agreement between Baker
Hughes Incorporated and each of the executive officers effective as of
January 1, 2009 (filed as Exhibit 10.2 to Current Report of Baker Hughes
Incorporated on Form 8-K filed December 19, 2008). |
85
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10.3+ |
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Stock Option Agreement issued to Chad C. Deaton on October 25, 2004 in the
amount of 75,000 shares of Company Common Stock (filed as Exhibit 10.4 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended September 30, 2004). |
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10.4+ |
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Agreement regarding restricted stock award issued to Chad C. Deaton on
October 25, 2004 in the amount of 80,000 shares of Company Common Stock
(filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended September 30, 2004). |
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10.5+ |
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Letter Agreement between Baker Hughes Incorporated and James R. Clark dated
August 30, 2007 (filed as Exhibit 10.1 to Current Report of Baker Hughes
Incorporated on Form 8-K filed August 31, 2007). |
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10.6+ |
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Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated
dated as of March 27, 2006 (filed as Exhibit 10.1 to Current Report of
Baker Hughes Incorporated on Form 8-K filed March 31, 2006). |
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10.7+ |
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Letter Agreement between Baker Hughes Incorporated and David H. Barr dated
October 25, 2007 (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended September 30, 2007). |
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10.8+ |
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Amendment and Restatement of the Baker Hughes Incorporated Change in
Control Severance Plan effective as of January 1, 2009 (filed as Exhibit
10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed
December 19, 2008). |
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10.9+ |
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Form of Indemnification Agreement between Baker Hughes Incorporated and
each of the directors and executive officers (filed as Exhibit 10.4 to
Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2003). |
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10.10+ |
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Form of Amendment to the Indemnification Agreement between Baker Hughes
Incorporated and each of the directors and executive officers effective as
of January 1, 2009 (filed as Exhibit 10.4 to Current Report of Baker Hughes
Incorporated on Form 8-K filed December 19, 2008). |
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10.11+ |
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Baker Hughes Incorporated Director Retirement Policy for Certain Members of
the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker
Hughes Incorporated on Form 10-K for the year ended December 31, 2003). |
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10.12+ |
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Baker Hughes Incorporated Director Compensation Deferral Plan, as amended
and restated effective as of January 1, 2009 (filed as Exhibit 10.2 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended June 30, 2008). |
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10.13+ |
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Amendment to Baker Hughes Incorporated Director Compensation Deferral Plan
effective as of January 1, 2009 (filed as Exhibit 10.5 to Current Report of
Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). |
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10.14+ |
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Baker Hughes Incorporated Executive Severance Plan, as amended and restated
on February 7, 2008 (filed as Exhibit 10.17 to Annual Report of Baker
Hughes Incorporated on Form 10-K for the year ended December 31, 2007). |
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10.15+ |
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Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended
and restated on February 20, 2008 (filed as Exhibit 10.18 to Annual Report
of Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2007). |
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10.16+ |
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Amendment to the Baker Hughes Annual Incentive Compensation Plan effective
as of January 1, 2009 (filed as Exhibit 10.7 to Current Report of Baker
Hughes Incorporated on Form 8-K filed on December 19, 2008). |
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10.17+ |
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Baker Hughes Incorporated Supplemental Retirement Plan, as amended and
restated effective as of January 1, 2009 (filed as Exhibit 10.1 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended June 30, 2008). |
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10.18+ |
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Amendment to the Baker Hughes Incorporated Supplemental Retirement Plan
effective as of January 1, 2009 (filed as Exhibit 10.6 to Current Report of
Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). |
86
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10.19+ |
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Long-Term Incentive Plan, as amended by Amendment No. 1999-1 to Long-Term
Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2002). |
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10.20+ |
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Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by
Amendment No. 1999-1 to 1998 Employee Stock Option Plan (filed as Exhibit
10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended June 30, 2003). |
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10.21+ |
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Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as
Exhibit 4.4 to Registration Statement No. 333-87372 of Baker Hughes
Incorporated on Form S-8 filed May 1, 2002). |
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10.22+ |
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Amendment to Baker Hughes Incorporated 2002 Employee Long-Term Incentive
Plan, effective July 24, 2008 (filed as Exhibit 10.4 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended
June 30, 2008). |
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10.23+ |
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Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan
(filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended September 30, 2003). |
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10.24+ |
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Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as
of October 27, 2005 (filed as Exhibit 10.3 of Baker Hughes Incorporated to
Quarterly Report on Form 10-Q for the quarter ended September 30, 2005). |
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10.25+ |
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Amendment to Baker Hughes Incorporated 2002 Director & Officer Long-Term
Incentive Plan effective July 24, 2008 (filed as Exhibit 10.3 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
June 30, 2008). |
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10.26 |
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Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and
restated, effective as of March 3, 2003 (filed as Exhibit 10.1 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
March 31, 2003). |
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10.27+ |
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Form of Stock Option Agreement for executive officers effective
October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2000). |
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10.28+ |
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Form of Nonqualified Stock Option Agreement for directors effective
October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2000). |
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10.29+ |
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Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for
executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to
Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2001). |
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10.30 |
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Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for
employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report
of Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2001). |
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10.31 |
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Form of Baker Hughes Incorporated Incentive Stock Option Agreement for
employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report
of Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2001). |
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10.32+ |
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Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms
and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2002). |
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10.33+ |
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Form of Restricted Stock Award Resolution, including Terms and Conditions
(filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended March 31, 2004). |
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10.34+ |
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Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed
as Exhibit 10.54 to Annual Report on Form 10-K for the year ended
December 31, 2004). |
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10.35+ |
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Form of Baker Hughes Incorporated Restricted Stock Award Terms and
Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual
Report on Form 10-K for the year ended December 31, 2004). |
87
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10.36 |
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Form of Baker Hughes Incorporated Restricted Stock Unit Agreement,
including Terms and Conditions (filed as Exhibit 10.18 to Annual Report of
Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2007). |
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10.37 |
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Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as
Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K
for the year ended December 31, 2004). |
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10.38 |
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Form of Baker Hughes Incorporated Restricted Stock Unit Terms and
Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual
Report on Form 10-K for the year ended December 31, 2004). |
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10.39+ |
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Form of Baker Hughes Incorporated Restricted Stock Award, including Terms
and Conditions for directors (filed as Exhibit 10.40 of Baker Hughes
Incorporated to Annual Report on Form 10-K for the year ended
December 31, 2005). |
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10.40+ |
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Form of Baker Hughes Incorporated Stock Option Award Agreement, including
Terms and Conditions for directors (filed as Exhibit 10.41 of Baker Hughes
Incorporated to Annual Report on Form 10-K for the year ended
December 31, 2005). |
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10.41+ |
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Form of Baker Hughes Incorporated Performance Unit Award Agreement,
including Terms and Conditions (filed as Exhibit 10.42 to Annual Report of
Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2007). |
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10.42+ |
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Form of Baker Hughes Incorporated Performance Unit Award Agreement,
including Terms and Conditions (filed as Exhibit 10.42 of Baker Hughes
Incorporated to Annual Report on Form 10-K for the year ended
December 31, 2005). |
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10.43+ |
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Form of Amended Baker Hughes Incorporated 2006 Performance Unit Award Terms
and Conditions (filed as Exhibit 10.8 to Current Report of Baker Hughes
Incorporated on Form 8-K filed December 19, 2008). |
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10.44+ |
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Form of Amended Baker Hughes Incorporated 2007 Performance Unit Award Terms
and Conditions (filed as Exhibit 10.9 to Current Report of Baker Hughes
Incorporated on Form 8-K filed December 19, 2008). |
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10.45+ |
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Performance Goals for the Performance Unit Award granted in 2006 (filed as
Exhibit 10.43 of Baker Hughes Incorporated to Annual Report on Form 10-K
for the year ended December 31, 2005). |
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10.46+ |
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Form of Performance Goals for the Performance Unit Awards (filed as Exhibit
10.44 of Baker Hughes Incorporated to Annual Report on Form 10-K for the
year ended December 31, 2006). |
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10.47+* |
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Compensation Table for Named Executive Officers and Directors. |
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10.48 |
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Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes
Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and
fourteen lenders for $500 million, in the aggregate for all banks (filed as
Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K
filed July 11, 2005). |
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10.49 |
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First Amendment to the Credit Agreement dated June 7, 2006, among Baker
Hughes Incorporated and fifteen banks for $500 million, in the aggregate
for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes
Incorporated on Form 8-K filed on June 12, 2006). |
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10.50 |
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Second Amendment to the Credit Agreement dated May 31, 2007, among Baker
Hughes Incorporated and fifteen banks for $500 million, in the aggregate
for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes
Incorporated on Form 8-K filed June 4, 2007). |
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10.51 |
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Third Amendment to Credit Agreement dated as of April 1, 2008, among Baker
Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent,
and fifteen lenders for $500 million, in the aggregate for all banks (filed
as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K
filed April 2, 2008). |
88
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10.52 |
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Credit Agreement dated as of April 1, 2008, among Baker Hughes
Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent, and
fifteen lenders for $500 million, in the aggregate for all banks (filed as
Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K
filed April 2, 2008). |
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10.53 |
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Agreement of Resignation, Appointment and Acceptance by and among Baker
Hughes Incorporated, Citibank, N.A. and the Bank of New York Trust Company,
N.A. dated as of April 26, 2007, effective May 1, 2007 (filed as Exhibit
10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended March 31, 2007). |
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10.54 |
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Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes
Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as
Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K
for the year ended December 31, 2003). |
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10.55 |
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Tax Sharing Agreement dated October 31, 1997, between Western Atlas Inc.
and UNOVA Inc. (filed as Exhibit 10.31 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2003). |
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10.56+ |
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Employee Benefits Agreement dated October 31, 1997, between Western Atlas
Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker
Hughes Incorporated on Form 10-K for the year ended December 31, 2003). |
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10.57 |
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Deferred Prosecution Agreement between Baker Hughes Incorporated and the
United States Department of Justice filed on April 26, 2007, with the
United States District Court of Texas, Houston Division (filed as Exhibit
10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended March 31, 2007). |
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10.58 |
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Plea Agreement between Baker Hughes Services International, Inc. and the
United States Department of Justice filed on April 26, 2007, with the
United States District Court of Texas, Houston Division (filed as Exhibit
10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended March 31, 2007). |
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10.59+* |
|
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Letter Agreement between Baker
Hughes Incorporated and David H. Barr dated February 25, 2009. |
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10.60+* |
|
|
Consulting Agreement between Baker
Hughes Oilfield Operations, Inc. and David H. Barr dated February 25,
2009. |
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21.1* |
|
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Subsidiaries of Registrant. |
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23.1* |
|
|
Consent of Deloitte & Touche LLP. |
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31.1* |
|
|
Certification of Chad C. Deaton, Chief Executive Officer, dated
February 26, 2009, pursuant to Rule 13a-14(a) of the Securities Exchange
Act of 1934, as amended. |
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31.2* |
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Certification of Peter A. Ragauss, Chief Financial Officer, dated
February 26, 2009, pursuant to Rule 13a-14(a) of the Securities Exchange
Act of 1934, as amended. |
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32* |
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Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss,
Chief Financial Officer, dated February 26, 2009, furnished pursuant to
Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended. |
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99.1 |
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Administrative Proceeding, File No. 3-10572, dated September 12, 2001, as
issued by the Securities and Exchange Commission (filed as Exhibit 99.1 to
Current Report of Baker Hughes Incorporated on Form 8-K filed on
September 19, 2001). |
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99.2 |
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Baker Hughes Incorporated Information document filed on April 26, 2007, by
the United States Attorneys Office for the Southern District of Texas and
the United States Department of Justice (filed as Exhibit 99.1 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
March 31, 2007). |
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99.3 |
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Baker Hughes Services International, Inc. Information document filed on
April 26, 2007, by the Untied States Attorneys Office for the Southern
District of Texas and the United States Department of Justice (filed as
Exhibit 99.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q
for the quarter ended March 31, 2007). |
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99.4 |
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Sentencing Memorandum and Motion for Waiver of Pre-Sentence Investigation
of Baker Hughes Services International, Inc. (filed as Exhibit 99.3 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended March 31, 2007). |
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89
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99.5 |
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Baker Hughes Services International, Inc. Sentencing Letter from the United
States Department of Justice dated April 24, 2007 (filed as Exhibit 99.4 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended March 31, 2007). |
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99.6 |
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The Complaint by the Securities and Exchange Commission vs. Baker Hughes
Incorporated filed on April 26, 2007, with the United States District Court
of Texas, Houston Division (filed as Exhibit 99.5 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended
March 31, 2007). |
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99.7 |
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Final Judgment by the Securities and Exchange Commission as to Defendant
Baker Hughes Incorporated dated and filed on May 1, 2007, with the United
States District Court of Texas, Houston Division (filed as Exhibit 99.1 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended June 30, 2007). |
90
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as
amended, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
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BAKER HUGHES INCORPORATED
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Date: February 26, 2009 |
/s/ CHAD C. DEATON |
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Chad C. Deaton |
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Chairman of the Board, President and Chief Executive Officer |
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91
KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Chad C. Deaton and Peter A. Ragauss, each of whom may act without joinder
of the other, as their true and lawful attorneys-in-fact and agents, each with full power of
substitution and resubstitution, for such person and in his or her name, place and stead, in any
and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file
the same, with all exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and
authority to do and perform each and every act and thing requisite and necessary to be done in and
about the premises, as fully to all intents and purposes as he might or could do in person, hereby
ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report
has been signed below by the following persons on behalf of the registrant and in the capacities
and on the dates indicated.
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Signature |
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Title |
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Date |
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/s/ CHAD C. DEATON
(Chad C. Deaton) |
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Chairman of the Board, President and Chief Executive Officer
(principal executive officer)
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February 26, 2009 |
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/s/ PETER A. RAGAUSS
(Peter A. Ragauss) |
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Senior Vice President and Chief Financial Officer
(principal financial officer) |
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February 26, 2009 |
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/s/ ALAN J. KEIFER
(Alan J. Keifer) |
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Vice President and Controller
(principal accounting officer) |
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February 26, 2009 |
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/s/ LARRY D. BRADY
(Larry D. Brady) |
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Director
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February 26, 2009 |
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/s/ CLARENCE P. CAZALOT, JR.
(Clarence P. Cazalot, Jr.) |
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Director
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February 26, 2009 |
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/s/ EDWARD P. DJEREJIAN
(Edward P. Djerejian) |
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Director
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February 26, 2009 |
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/s/ ANTHONY G. FERNANDES
(Anthony G. Fernandes) |
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Director
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February 26, 2009 |
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/s/ CLAIRE W. GARGALLI
(Claire W. Gargalli) |
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Director
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February 26, 2009 |
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/s/ PIERRE H. JUNGELS
(Pierre H. Jungels) |
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Director
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February 26, 2009 |
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/s/ JAMES A. LASH
(James A. Lash) |
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Director
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February 26, 2009 |
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/s/ JAMES F. MCCALL
(James F. McCall) |
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Director
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February 26, 2009 |
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/s/ J. LARRY NICHOLS
(J. Larry Nichols) |
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Director
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February 26, 2009 |
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/s/ H. JOHN RILEY, JR.
(H. John Riley, Jr.) |
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Director
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February 26, 2009 |
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/s/ CHARLES L. WATSON
(Charles L. Watson) |
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Director
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February 26, 2009 |
92
Baker Hughes Incorporated
Schedule II Valuation and Qualifying Accounts
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Deductions |
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Additions |
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Balance at |
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Charged to |
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Reversal of |
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Charged to |
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Balance at |
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Beginning |
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Cost and |
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Prior |
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Write-offs |
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Other |
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End of |
(In millions) |
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of Period |
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Expenses |
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Deductions(1) |
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(2) |
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Accounts(3) |
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Period |
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Year ended December 31, 2008: |
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Reserve for doubtful accounts receivable |
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$ |
59 |
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$ |
49 |
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$ |
(18 |
) |
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$ |
(15 |
) |
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$ |
(1 |
) |
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$ |
74 |
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Reserve for inventories |
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221 |
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61 |
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(30 |
) |
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(8 |
) |
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244 |
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Year ended December 31, 2007: |
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Reserve for doubtful accounts receivable |
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51 |
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36 |
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(14 |
) |
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(10 |
) |
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(4 |
) |
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59 |
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Reserve for inventories |
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|
212 |
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|
|
43 |
|
|
|
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(37 |
) |
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3 |
|
|
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221 |
|
|
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Year ended December 31, 2006: |
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|
|
|
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Reserve for doubtful accounts receivable |
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|
51 |
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28 |
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(20 |
) |
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(11 |
) |
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3 |
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51 |
|
Reserve for inventories |
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|
201 |
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45 |
|
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(38 |
) |
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4 |
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212 |
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|
|
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(1) |
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Represents the reversals of prior accruals as receivables are collected. |
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(2) |
|
Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless. |
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(3) |
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Represents reclasses, currency translation adjustments and divestitures. |
93