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, 2006
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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
(State or other jurisdiction of incorporation or organization)
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76-0207995
(I.R.S. Employer Identification No.) |
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2929 Allen Parkway, Suite 2100, Houston, Texas
(Address of principal executive offices)
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77019-2118
(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 |
Common Stock, $1 Par Value per Share
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New York Stock Exchange
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 þ NO o
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer.
Large accelerated filer þ
Accelerated filer o
Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). YES o NO þ
The aggregate market value of 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, 2006 reported by the New York Stock Exchange) was approximately
$26,970,000,000.
As
of February 22, 2007, the registrant has outstanding
320,240,728 shares of common
stock, $1 par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrants 2006 Proxy Statement for the Annual Meeting of Stockholders to be
held April 26, 2007 are incorporated by reference into Part III of this Form 10-K.
Baker Hughes Incorporated
INDEX
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PART I
ITEM 1. BUSINESS
Baker Hughes Incorporated (Baker Hughes, Company, we, our or us) is a Delaware
corporation engaged in the oilfield services industry. Baker Hughes is a major supplier of
products and technology services and systems to the worldwide oil and natural gas industry,
including products and services for drilling, formation evaluation, completion and production of
oil and natural gas wells. We may conduct our operations through subsidiaries, affiliates,
ventures and alliances.
Baker Hughes was formed in April 1987 in connection with the combination of Baker
International Corporation and Hughes Tool Company. We acquired Western Atlas Inc. in a merger
completed on August 10, 1998.
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.
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).
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 our website information about any amendment or
waiver of these codes for our executive officers and directors. 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 Certification, 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
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 are a provider of drilling, formation evaluation, completion and production products and
services to the worldwide oil and natural gas industry. We report our results under three segments
- Drilling and Evaluation, Completion and Production and WesternGeco. The WesternGeco segment
consisted of our 30% interest in WesternGeco, a seismic venture with Schlumberger Limited
(Schlumberger). On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger.
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 include 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.
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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. The Drilling and Evaluation
segment provides products and services used to drill and evaluate oil and natural gas
wells. |
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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) and Centrilift
(electrical submersible pumps and progressing cavity pumps) divisions and the
ProductionQuest business unit. 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, 2006, see
Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.
DRILLING AND EVALUATION SEGMENT
Baker Hughes Drilling Fluids
Baker Hughes Drilling Fluids is a major provider of drilling fluids (also called mud),
completion fluids (also called brines) and fluids environmental services (also called waste
management). Drilling fluids 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, Baker Hughes Drilling Fluids drill-in or completion fluids
possess properties that minimize formation damage. Fluids environmental services of Baker Hughes
Drilling Fluids also provides equipment and services to separate the drill cuttings from the
drilling fluids and re-inject the processed cuttings into specially prepared wells, or to transport
and dispose 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. |
Baker Hughes Drilling Fluids primary competitors include M-I SWACO, Halliburton Company
(Halliburton) and Newpark Resources, Inc.
Key business drivers for Baker Hughes Drilling Fluids 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.
Hughes Christensen
Hughes Christensen is a leading manufacturer and supplier of drill bits, primarily Tricone®
roller cone bits and fixed-cutter polycrystalline diamond compact (PDC) bits, to the worldwide
oil and natural gas industry. The primary objective of a drill bit is to drill a high quality
wellbore as efficiently as possible.
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 Bits. 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®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.
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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 distance 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. |
Hughes Christensens primary competitors in the oil and natural gas drill bit market include
Smith International, Inc. (Smith), Grant Prideco, Inc. and Halliburton.
Key business drivers for Hughes Christensen include the number of drilling rigs operating,
total footage drilled, drilling rig rental costs, as well as the current and expected future price
of both oil and natural gas.
INTEQ
INTEQ is a leading supplier of drilling and evaluation services, which include directional
drilling, measurement-while-drilling (MWD) and logging-while-drilling (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.
INTEQ is a leading supplier of 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.
INTEQ 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, INTEQs 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.
INTEQs 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. INTEQs 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 them in real-time often
allows for greater accuracy, as measurements occur before any damage has been sustained by the
reservoir as a result of the drilling process. 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.
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As part of INTEQs mud logging services, 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. |
INTEQs primary competitors in drilling and evaluation services include Halliburton,
Schlumberger and Weatherford International Ltd. (Weatherford).
Key business drivers for INTEQ include the number of drilling rigs operating, the total
footage drilled, the mix of conventional and rotary steerable systems used, technological
sophistication of the wells being drilled, as well as the current and expected future price of both
oil and natural gas.
Baker Atlas
Baker Atlas is a leading provider of formation evaluation and wireline completion and
production services for oil and natural gas wells.
Formation Evaluation. 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 providing 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. Formation evaluation tools
can also be used to record formation pressures and take samples of formation fluids to be further
evaluated on the surface.
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 (performed by Baker Atlas) and LWD (performed by INTEQ). 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). Baker Atlas also offers 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. Baker Atlas (and Baker Oil Tools) 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.
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Baker Atlas 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 from the formation, |
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the efficiency of providing wireline completion and production services at the wellsite, and |
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the ability to differentiate services that can run exclusively or more efficiently on
wireline from services that can run on either wireline or drill pipe. |
Baker Atlas primary formation evaluation and wireline completion and perforating competitors
include Schlumberger, Halliburton and Weatherford.
Key business drivers for Baker Atlas include the number of drilling and workover rigs
operating, as well as the current and expected future price of both oil and natural gas.
COMPLETION AND PRODUCTION SEGMENT
Baker Oil Tools
Baker Oil Tools 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. Baker Oil Tools 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.
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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. In this area, Baker Oil Tools
offerings range from service tools and inflatable products to conventional and through-tubing
fishing systems, casing exits, wellbore cleaning and temporary abandonment.
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. |
Baker Oil Tools primary competitors in wellbore construction, cased-hole completions and sand
control include Halliburton, Schlumberger and Weatherford. Its primary competitors in wellbore
intervention include Weatherford and Smith.
Key business drivers for Baker Oil Tools 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.
Baker Petrolite
Baker Petrolite is a leading provider of specialty chemicals to the oil and gas industry. The
division also supplies specialty chemicals to a number of industries including refining, pipeline
transportation, petrochemical, agricultural and iron and steel manufacturing and provides
polymer-based products to a broad range of industrial and consumer markets. Through its Pipeline
Management Group (PMG), Baker Petrolite also offers a variety of products and services for the
pipeline transportation industry.
Oilfield Chemicals. Baker Petrolite provides oilfield chemical programs for drilling, well
stimulation, production, pipeline transportation and maintenance programs. Its products provide
measurable increases in productivity, decreases in operating and maintenance cost 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.
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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. Baker Petrolite offers solvents that remove the
deposits, as well as inhibitors that prevent new deposits from forming.
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. Baker Petrolite offers 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. Baker Petrolite offers emulsion breakers that allow the water to be separated from
the oil.
Refining, Industrial and Other Specialty Chemicals. For the refining industry, Baker
Petrolite offers 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. Baker Petrolite also provides chemical
technology solutions to other industrial markets throughout the world, including petrochemicals,
fuel additives, plastics, imaging, adhesives, steel and crop protection.
Pipeline Management. Baker Petrolites Pipeline Management Group (PMG) offers a variety of
products and services for the pipeline transportation industry. To improve efficiency, Baker
Petrolite offers custom turnkey cleaning programs that combine 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,
PMGs 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. |
Baker Petrolites primary competitors include GE Water Technologies, Nalco Holding Company,
Champion Technologies and Smith.
Key business drivers for Baker Petrolite 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.
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Centrilift
Centrilift is a leading manufacturer and supplier of 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. Centrilift designs,
manufactures, markets and installs all the components of ESP systems 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 ESP systems is expanding as technology and
reliability enhancements have improved ESP system performance in harsher environments and marginal
reservoirs.
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. PCP systems are preferred when the fluid to be lifted is viscous or when the volume
is significantly less than could be economically lifted with an ESP system.
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. |
Centrilifts primary competitors in the ESP market include Schlumberger and John Wood Group
PLC (ESP Inc.). In the PCP market, the primary competitors include Weatherford, Robbins & Myers,
Inc. and Kudu Industries, Inc.
Key business drivers for Centrilift 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.
ProductionQuest
The ProductionQuest business unit is a provider of permanent monitoring systems and chemical
automation 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.
ProductionQuest is 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, they provide chemical injection line installation and services for treating wells for
corrosion, paraffin, scale and other well performance problems. They 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 for 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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innovative products, |
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gauge measurement accuracy, |
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product life and performance, and |
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installation and service capabilities. |
ProductionQuests primary competitors include Schlumberger, Halliburton and Weatherford.
Key business drivers for ProductionQuest 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).
WesternGeco
WesternGeco is a seismic venture in which we previously owned 30% and Schlumberger owned 70%.
On April 28, 2006, we sold our 30% interest to Schlumberger for $2.4 billion in cash. We recorded
a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax).
For additional information related to WesternGeco, see the Related Party Transactions
section in Item 7 and Note 5 of the Notes to Consolidated Financial Statements in Item 8, both
contained herein.
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. 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 contained 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, both contained herein.
INTERNATIONAL OPERATIONS
We operate in over 90 countries worldwide, and 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 contained in Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
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, 2006, see Note 16 of the Notes to Consolidated Financial Statements in Item 8
herein.
10
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.
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, 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 could be subject to rising costs. 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, 2006, we had approximately 34,600 employees, as compared with approximately
29,100 employees on December 31, 2005. Approximately 2,700 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. We believe that our relations with our employees are good.
EXECUTIVE OFFICERS
The following table shows, as of February 23, 2007, the name of each of our executive
officers, together with his age and all offices presently held.
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Chad C. Deaton
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54 |
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Chairman of the Board and Chief Executive
Officer of the Company since October 2004.
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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James R. Clark
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56 |
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President and Chief Operating Officer of
the Company since February 2004. Vice
President, Marketing and Technology of the
Company from 2003 to 2004. Vice President
of the Company and President of Baker
Petrolite Corporation from 2001 to 2003.
President and Chief Executive Officer of
Consolidated Equipment Companies, Inc. from
2000 to 2001 and President of Sperry-Sun
from 1996 to 1999. Employed by the Company
in 2001. |
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Peter A. Ragauss
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49 |
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Senior Vice President and Chief Financial
Officer of the Company since April 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. Served as Vice
President of Finance and Portfolio
Management for Amoco Energy International
immediately prior to its merger with BP in
1998. Employed by the Company in 2006. |
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Alan R. Crain, Jr.
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55 |
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Senior Vice President and General Counsel
since January 2007. Vice President and
General Counsel of the Company from October
2000 to January 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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Didier Charreton*
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43 |
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Vice President, Human Resources in 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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David H. Barr
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57 |
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Group President of Drilling and Evaluation
since February 2005 and Vice President of
the Company since 2000. 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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Douglas J. Wall
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54 |
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Group President of Completion and
Production since February 2005 and Vice
President of the Company since 1997.
President of Baker Oil Tools from 2003 to
2005 and President of Hughes Christensen
from 1997 to 2003. President and Chief
Executive Officer of Western Rock Bit
Company Limited, Hughes Christensens
former distributor in Canada, from 1991 to
1997. General Manager of Century Valve
Company from 1989 to 1991 and Vice
President, Contracts and Marketing, of
Adeco Drilling & Engineering from 1980 to
1989. Employed by the Company in 1997. |
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Christopher P. Beaver
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49 |
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Vice President of the Company and President
of Baker Oil Tools since February 2005.
Vice President of Finance for Baker
Petrolite from 2002 to 2005; Director of
Finance and Controller at INTEQ from 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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50 |
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Vice President of the Company since 2005
and President of Baker Atlas since
September 2006. President Hughes
Christensen from 2005 to September 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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Martin S. Craighead
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47 |
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Vice President of the Company since 2005
and President of INTEQ since August 2005.
Served as 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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Alan J. Keifer
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52 |
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Vice President and Controller of the
Company since July 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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55 |
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Vice President, Chief Compliance Officer
and Senior Deputy General Counsel since
July 2004. Shareholder at Winstead
Sechrest & Minick P.C. from 2001 to July
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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John A. ODonnell
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58 |
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Vice President of the Company since 1998
and President of Baker Petrolite
Corporation since May 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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Mr. Charreton will join the Company as Vice President, Human Resources on or before March 1,
2007. |
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Gary G. Rich
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48 |
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Vice President of the Company and President
of Hughes Christensen since September 2006.
Vice President Marketing, Drilling and
Evaluation for INTEQ from 2005 to 2006. Mr.
Rich was 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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Richard L. Williams
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51 |
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Vice President of the Company and President
of Baker Hughes Drilling Fluids since May
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. Vice President Western Hemisphere,
INTEQ from 2001 to 2003. Employed by the
Company in 1975. |
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Charles S. Wolley
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52 |
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Vice President of the Company and President
of Centrilift since January 2006. Vice
President of Manufacturing and Technology,
Hughes Christensen from 2004 to 2006. Senior
Vice President of Supply Chain Operations,
Dresser Flow Solutions 2003. President,
Dresser Measurement and Control from 2002 to
2003 and Senior Vice President from 2001 to
2002. Chief Executive Officer Van Leeuwen
Pipe and Tube Corp. from 1999 to 2001.
Employed by the Company since 2004. |
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.
Remediation costs are accrued based on estimates of probable exposure 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. Such accruals are recorded 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. Such 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.
During the year ended December 31, 2006, we spent approximately $35.1 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 2007, we expect to spend approximately $40.5 million to comply with
Environmental Regulations. During the year ended December 31, 2006, we incurred approximately $5.8
million in capital expenditures for environmental control equipment, and we estimate we will incur
approximately $7.8 million during 2007.
In addition, we estimate we will incur approximately $19 million in
capital expenditures for the relocation of an existing plant in the
U.K. to comply with local environmental regulations of which
approximately $13 million will be spent in 2007 and the remainder in
2008.
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.
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. 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. With the joint and
several liability imposed under Superfund, a PRP may be required to pay more than its proportional
share of such costs.
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We have been identified as a PRP at various Superfund sites discussed below. The United
States Environmental Protection Agency (the EPA) and appropriate state agencies supervise
investigative and cleanup activities at these sites. For the year ended December 31, 2006, we paid
$0.2 million in Superfund costs and have accrued an additional $5.9 million related to these sites.
Payments made in 2006 are in addition to amounts previously paid in settlements, cash calls or
other Superfund costs, and these ongoing contributions reduce our financial liability for the total
site cleanup costs shown below. When used in the descriptions of the sites that follow, the word
de minimis refers to the smallest PRPs, whose contribution rate is usually less than 1%.
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In 1999, Baker Oil Tools, Baker Petrolite and predecessor entities of Baker Petrolite
were named as PRPs by the State of Californias Department of Toxic Substances Control for
the Gibson site in Bakersfield, California. Costs are now estimated at $6.0 million to $7.0
million, of which $5.0 million has been raised. Allocation information has been updated and
our combined volume is now 1.6% for liquids and 0.4% for solids. |
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In 2001, a Hughes Christensen predecessor, Baker Oil Tools, INTEQ and one of our former
subsidiaries were named as PRPs in the Force Road State Superfund site located in Brazoria
County, Texas. The Texas Commission on Environmental Quality (TCEQ) is overseeing the
investigation and remediation at the Force Road site. We participate as a member of the
steering and technical committees to effectively manage the project because our volumetric
contribution is currently estimated at approximately 76%. The onsite investigation was
completed in late 2005, and the offsite investigation is expected to be complete in early
2007. The estimate of site remediation costs used for initial settlement purposes was $17.7
million; however, we anticipate that a more accurate calculation of site remediation costs
will be possible once the offsite investigation is complete. Approximately $1.8 million has
been raised from de minimis settlements. We believe that after negotiation of additional
early settlements with other PRPs, future cost recovery actions against recalcitrant
parties, development of remedial alternatives and other factors, our ultimate share of
responsibility for cleanup costs at the site will be less than initial estimates. |
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In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and several of our
former subsidiaries were identified as PRPs for the Malone site located on Campbell Bayou
Road in Texas City, Texas. The EPA oversees the investigation and remediation of the Malone
site and has engaged in emergency removal actions. The investigation is nearly complete and
remedial alternatives have been developed and submitted to the EPA for evaluation. The
estimates for the various cleanup options at the Malone site range from $28.0 million to
almost $400.0 million with the most likely scenarios in the range of $40.0 million to $80.0
million. Our contribution is currently estimated at approximately 1.7 %. A lawsuit filed
by the current owners of the site and a related entity against the PRPs seeking recovery of
certain alleged damages has not been fully resolved, and may affect the ultimate costs
associated with this Superfund site. |
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In 2003, we were identified as a de minimis PRP by the EPA for the Operating Industries,
Inc. Superfund site in Monterrey Park, California. A settlement offer to all remaining de
minimis parties has been repeatedly delayed, but is now expected in 2007. The EPA and
Steering Committee have incurred $345 million and expect an additional $367 million in
cleanup costs. Information provided by the EPA in 2007 indicates that our contribution is
..092%, although our ultimate liability has yet to be negotiated and may include a premium
for early settlement. |
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In 2003, Baker Petrolite was notified by the EPA of their potential involvement at the
Cooper Drum Superfund site located in South Gate, California. We responded to an additional
inquiry from the EPA in 2005. At this time there is no estimate available for comprehensive
cleanup costs or our allocation and, accordingly, the extent of our financial liability at
the site is unknown. |
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(f) |
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In 2006, we were one of five PRPs to receive an information request from the EPA
regarding the Washington County Lead District Superfund site, a federal Superfund located in
Washington County, Missouri. We have responded to the EPA regarding our involvement with
two of the six mines listed in the information request. A preliminary screening and
removal action has been completed by the EPA to evaluate the impacts of lead and other heavy
metals on the soil and groundwater in the area; however, the project is still in the initial
stages and there is insufficient information to estimate our potential contribution to the
cleanup costs. |
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(g) |
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In 2006, Baker Petrolite received a General Notice of Potential Liability letter from the
EPA concerning the RRG/Clayton Chemical Superfund site in Sauget, Illinois and its impact on
the adjacent Sauget Area 2 Groundwater Superfund site. We have participated in cleanup
activities at the Clayton site as a small party with an allocation just over the de minimis
level. Our ultimate liability may now include some responsibility for the downgradient
groundwater cleanup at the Sauget Area 2 Groundwater Superfund site, but insufficient
information is available to estimate the potential cost to the Company. |
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(h) |
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In 2006, a settlement demand was received from the PRP Group for the Pulvair Superfund
site located in Millington, Tennessee for waste sent to the site by Milchem, a predecessor
to Baker Hughes Drilling Fluids. The matter has not yet been resolved, but is expected to
be settled at a cost of less than $0.2 million. |
In addition to the sites mentioned above, there are four Superfund sites where we have ongoing
obligations. The remedial work at most of these sites has been completed and remaining operations
are limited to groundwater recovery and/or monitoring. The monitoring phase can continue for up to
30 years. Our aggregate cost for these sites is estimated to be approximately $0.1 million over
this period of time. There were also four Superfund sites that were settled during 2006 at a
combined cost of less than $0.2 million.
While PRPs in Superfund actions have joint and several liability for all costs of remediation,
it is not possible at this time to quantify our ultimate exposure because some of the projects are
either in the investigative or early remediation stage. However, based upon current information,
we do not believe that probable or reasonably possible expenditures in connection with the sites
described above 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.
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.
Environmental Matters contains forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Exchange
Act (each a Forward-Looking Statement). The words will, believe, to be, expect,
estimate and similar expressions are intended to identify forward-looking statements. 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) the Superfund sites described above; 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 in the course of our business or operations; a
catastrophic event causing discharges into the environment; or an acquisition of one or more new
businesses.
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. These risks and
uncertainties are not the only ones facing us and there may be additional matters that we are
unaware of or that we currently consider immaterial. All 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 and the future value of the
hydrocarbon reserves. Their evaluation of the future value is based, in part, on their
expectations for global demand, global supply 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.
Growth in worldwide 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. and China, who are significant users of oil and natural gas. Increases
in global economic activity, particularly in China and developing Asia, create more demand for oil
and
15
natural gas and higher oil and natural gas prices. A slowing of global economic growth, and
in particular in the U.S. or China, will likely reduce demand for oil and natural gas, increase
spare productive capacity and result in lower prices and adversely impact the demand for our
services.
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. While current energy prices are important contributors to
positive cash flow for our customers, expectations about future prices and price volatility are
generally more important for determining future spending levels. 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.
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 and capital are 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. Access to capital is
dependent on our customers ability to access the funds necessary to develop economically
attractive projects based on their expectations of future energy prices, required investments and
resulting returns. 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 be interrupted by a number of factors including political instability, civil
unrest, labor issues, terrorist attacks, war or military activity. Key oil producing countries
which could be subject to supply interruptions include, but are not limited to, Saudi Arabia, Iran,
Iraq and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela. The impact of
supply disruptions on oil and natural gas prices and oil and natural gas price volatility is
tempered by the size and expected duration of the disruption relative to the spare productive
capacity at the time of the disruption.
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.
Spare productive capacity and future demand impact our operations.
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.
16
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 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 our customers. Our ability to 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 materials, equipment, supplies and personnel 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, copper, carbide, chemicals
and electronic components. 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. Rapid growth presents 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. Labor-related
actions, including strikes, slowdowns and facility occupations can also have a negative impact on
our business.
Compliance with and changes in laws and regulations and risks from investigations and legal
proceedings could be costly and could adversely affect operating results.
Our operations in the U.S. and over 90 countries can be impacted by expected and unexpected
changes in the legal and business environments in which we operate, as well as the outcome of
ongoing government and internal investigations and legal proceedings such as the previously
reported investigations by the Securities and Exchange Commission (SEC) and the Department of
Justice (DOJ). Our ability to manage our compliance costs will impact our ability to meet our
earnings goals. While we have reserved our best estimate of the financial charge related to the
resolution of the investigations with the SEC and DOJ regarding the investigations into our
activities in Angola, Kazakhstan, and Nigeria, there is no assurance that we will be able to reach
an acceptable settlement and that the settlement will be approved by the appropriate U.S. District
Court. If we do not reach a negotiated settlement with the SEC or the DOJ, it is likely that the
SEC and/or DOJ will seek civil and criminal sanctions against us as well as fines and penalties
that may be in excess of the current estimated reserved amount. In addition, we may incur
additional costs arising from compliance and ongoing or additional investigations in any of the
countries where we do business.
Changes that could impact the legal environment include new legislation, new regulation, new
policies, investigations and legal proceedings and new interpretations of the 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
17
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. Additional taxes may also be incurred or
assessed as a result of any resolution with the SEC and DOJ. Compliance related issues could limit
our ability to do business in certain countries.
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 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.
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. Changes in our environmental liability could originate with the discovery of new
environmental remediation sites, changes in environmental regulations, or the discharge of
hazardous materials into the environment.
Changes in economic conditions and currency fluctuations may adversely affect our operating
results.
Fluctuations in foreign currencies relative to the U.S. Dollar can impact 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. 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, Australian Dollar and Brazilian Real, can increase or decrease our
expenses reported in U.S. Dollars and impact our operating margins. 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 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 the consolidated statements of operations as incurred. Such
transaction and translation losses may adversely 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 our costs under our $500.0 million revolving credit agreement, as
well as the cost of obtaining, or make it more difficult to 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.
18
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We are headquartered in Houston, Texas and operate 46 principal manufacturing plants, ranging
in size from approximately 5,000 to 300,000 square feet of manufacturing space. The total area of
the plants is approximately 3.2 million square feet, of which approximately 2.1 million square feet
(65.5%) are located in the United States, 0.4 million square feet (10.9%) are located in Canada and
South America, 0.7 million square feet (21.7%) are located in Europe, and a minimal amount of space
is located in the Far East. Our principal manufacturing plants are located in: United States
Houston, Texas; Broken Arrow and Claremore, Oklahoma; Lafayette, Louisiana; South America various
cities in Venezuela; and Europe Aberdeen and East Kilbride, Scotland; Liverpool, England; Celle,
Germany; Belfast, Northern Ireland.
We own or lease numerous service centers, shops and sales and administrative offices
throughout the geographic areas 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 area:
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Canada |
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|
|
|
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|
and |
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|
|
|
|
|
Segment |
|
United States |
|
South America |
|
Europe |
|
Far East |
|
Total |
Completion and Production |
|
|
16 |
|
|
|
4 |
|
|
|
7 |
|
|
|
1 |
|
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and Evaluation |
|
|
13 |
|
|
|
1 |
|
|
|
3 |
|
|
|
1 |
|
|
|
18 |
|
ITEM 3. LEGAL PROCEEDINGS
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 related to these
types of claims. 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 Securities and Exchange Commission (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 Department
of Justice (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 Foreign Corrupt Practices Act
(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
19
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 are
conducting investigations into allegations of violations of law relating to Nigeria and other
related matters. The SEC has issued a formal order of investigation into possible violations of
provisions under the FCPA regarding anti-bribery, books and records and internal controls. The SEC
has 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 ongoing
investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ
and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former
employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In
addition, we have conducted internal investigations into these matters.
Our internal investigations have 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 Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental
authorities in Nigeria. The investigation in Nigeria was substantially completed during the first
quarter of 2003 and, based upon current information, we do not expect that any such potential
liabilities will have a material adverse effect on our consolidated financial statements. The
internal investigations in Angola and Kazakhstan were substantially completed in the third quarter
of 2004. Evidence obtained during the course of the investigations has been provided to the SEC
and DOJ.
In 2004, we received a subpoena from a grand jury in the Southern District of New York
regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations
Oil-for-Food Program. In 2004, we also received a request from the SEC to provide a written
statement and certain information regarding our participation in that program. We have responded
to both the subpoena and the request and may provide additional materials.
The DOJ, the SEC and other agencies and authorities have a broad range of civil and criminal
sanctions they may seek to impose against corporations and individuals in appropriate circumstances
including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications
to business practices and compliance programs. Such agencies and authorities have entered into
agreements with, and obtained a range of sanctions against, several public corporations and
individuals arising from allegations of improper payments and deficiencies in books and records and
internal controls, whereby civil and criminal penalties were imposed, including in some cases
multi-million dollar fines and other sanctions.
The Company has engaged in settlement discussions with both the DOJ and SEC concerning the
issues in Nigeria, Angola and Kazakhstan. There can be no assurance that such discussions will
result in a resolution of any or all of these issues; however, we have determined that the
settlement discussions are likely to result in a resolution that will include both civil and
criminal sanctions as well as significant fines and penalties. Our best estimate of the associated
financial charge of $46.1 million was recorded in the fourth quarter of 2006 and is included in
selling, general and administrative expenses. If a resolution is not concluded, we believe it is
probable that the DOJ and SEC will seek civil and criminal sanctions against us as well as fines
and penalties. If ultimately imposed, or if agreed to by settlement, such fines and penalties may
exceed the current amount we have estimated and reserved. It is not possible to accurately predict
at this time when any of the investigations will be finally resolved.
Further information is contained in the Environmental Matters section of Item 1 herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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 22, 2007,
there were approximately 114,100 stockholders and
approximately 16,700 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, 2006, and information regarding
dividends declared on our common stock during the two years ended December 31, 2006, see Note 17 of
the Notes to Consolidated Financial Statements in Item 8 herein.
20
The following table contains information about our purchases of equity securities during
the fourth quarter of 2006.
Issuer Purchases of Equity Securities
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Maximum Number (or |
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Total Number |
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Approximate Dollar |
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|
|
of Shares Purchased |
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|
|
Value) of Shares |
|
|
Total Number of |
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|
|
as Part of a |
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|
|
|
|
|
|
|
|
that May Yet Be |
|
|
Shares |
|
Average Price |
|
Publicly Announced |
|
Average Price |
|
Total Number |
|
Purchased Under the |
|
|
Purchased |
|
Paid Per Share |
|
Program |
|
Paid Per Share |
|
of Shares Purchased |
|
Program |
Period |
|
(1) |
|
(1) |
|
(2) |
|
(3) |
|
in the Aggregate |
|
(4) |
|
October
131, 2006 |
|
|
7,318 |
|
|
$ |
72.97 |
|
|
|
3,360,000 |
|
|
$ |
69.89 |
|
|
|
3,367,318 |
|
|
$ |
|
|
November
130, 2006 |
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December
131, 2006 |
|
|
9,112 |
|
|
|
66.68 |
|
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|
|
|
|
|
|
|
|
|
9,112 |
|
|
|
|
|
|
Total |
|
|
16,430 |
|
|
$ |
69.48 |
|
|
|
3,360,000 |
|
|
$ |
69.89 |
|
|
|
3,376,430 |
|
|
$ |
345,500,000 |
|
|
|
|
|
(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 2,
2006 we entered into the Plan that ran from August 2, 2006 until October 31, 2006. 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) |
|
On October 27, 2005, the Board of Directors authorized us to repurchase up to
$455.5 million of common stock, which was in addition to the balance of $44.5 million
remaining from the Board of Directors September 2002 authorization, resulting in the
authorization to repurchase up to a total of $500.0 million of common stock. In April 2006,
the Board of Directors authorized the repurchase of an additional $1.8 billion of common
stock. At December 31, 2006, we had authorization remaining to repurchase up to a total of
$345.5 million of our common stock. |
Under our Employee Stock Purchase Plan (the Plan), in December 2003, 2004 and 2005, we
issued an aggregate of up to 1,552,505 shares of common stock at a price per share of $27.19,
$27.34 and $36.27, respectively, without registration under the Securities Act. While included in
an amendment to the Plan that was approved by the stockholders, these shares were not covered by
registration statements previously filed with respect to the Plan. These shares were registered on
November 8, 2006.
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 Oil and Gas Equipment and Services Index over the preceding
five-year period.
21
Comparison of Five-Year Cumulative Total Return *
Baker Hughes Incorporated; S&P 500 Index and S&P Oil and Gas Equipment and Services Index
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2001 |
|
2002 |
|
2003 |
|
2004 |
|
2005 |
|
2006 |
|
|
|
Baker Hughes |
|
$ |
100.00 |
|
|
$ |
89.58 |
|
|
$ |
90.90 |
|
|
$ |
122.06 |
|
|
$ |
175.50 |
|
|
$ |
217.05 |
|
S&P 500 Index |
|
|
100.00 |
|
|
|
77.90 |
|
|
|
100.24 |
|
|
|
111.15 |
|
|
|
116.61 |
|
|
|
135.02 |
|
S&P Oil and Gas Equipment and Services Index |
|
|
100.00 |
|
|
|
88.52 |
|
|
|
110.41 |
|
|
|
145.59 |
|
|
|
216.31 |
|
|
|
249.92 |
|
|
|
|
* |
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, 2001 in Baker Hughes common stock, the
S&P 500 Index and the S&P 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.
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|
Year Ended December 31, |
(In millions, except per share amounts) |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
Revenues |
|
$ |
9,027.4 |
|
|
$ |
7,185.5 |
|
|
$ |
6,079.6 |
|
|
$ |
5,233.3 |
|
|
$ |
4,843.5 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of revenues and research and engineering |
|
|
5,782.4 |
|
|
|
4,942.5 |
|
|
|
4,351.0 |
|
|
|
3,807.5 |
|
|
|
3,478.5 |
|
Selling, general and administrative |
|
|
1,310.7 |
|
|
|
1,009.6 |
|
|
|
912.2 |
|
|
|
824.6 |
|
|
|
805.5 |
|
Impairment of investment in affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45.3 |
|
|
|
|
|
Restructuring charge reversals |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.1 |
) |
|
|
|
|
|
Total costs and expenses |
|
|
7,093.1 |
|
|
|
5,952.1 |
|
|
|
5,263.2 |
|
|
|
4,676.3 |
|
|
|
4,284.0 |
|
|
Operating income |
|
|
1,934.3 |
|
|
|
1,233.4 |
|
|
|
816.4 |
|
|
|
557.0 |
|
|
|
559.5 |
|
Equity in income (loss) of affiliates |
|
|
60.4 |
|
|
|
100.1 |
|
|
|
36.3 |
|
|
|
(137.8 |
) |
|
|
(69.7 |
) |
Gain on sale of interest in affiliate |
|
|
1,743.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(68.9 |
) |
|
|
(72.3 |
) |
|
|
(83.6 |
) |
|
|
(103.1 |
) |
|
|
(111.1 |
) |
Interest and dividend income |
|
|
67.5 |
|
|
|
18.0 |
|
|
|
6.8 |
|
|
|
5.3 |
|
|
|
5.2 |
|
|
Income from continuing operations before income
taxes |
|
|
3,736.8 |
|
|
|
1,279.2 |
|
|
|
775.9 |
|
|
|
321.4 |
|
|
|
383.9 |
|
Income taxes |
|
|
(1,338.2 |
) |
|
|
(404.8 |
) |
|
|
(250.6 |
) |
|
|
(145.6 |
) |
|
|
(157.9 |
) |
|
Income from continuing operations |
|
|
2,398.6 |
|
|
|
874.4 |
|
|
|
525.3 |
|
|
|
175.8 |
|
|
|
226.0 |
|
Income (loss) from discontinued operations, net of
tax |
|
|
20.4 |
|
|
|
4.9 |
|
|
|
3.3 |
|
|
|
(41.3 |
) |
|
|
(14.6 |
) |
|
Income before cumulative effect of accounting
change |
|
|
2,419.0 |
|
|
|
879.3 |
|
|
|
528.6 |
|
|
|
134.5 |
|
|
|
211.4 |
|
Cumulative effect of accounting change, net of tax |
|
|
|
|
|
|
(0.9 |
) |
|
|
|
|
|
|
(5.6 |
) |
|
|
(42.5 |
) |
|
Net income |
|
$ |
2,419.0 |
|
|
$ |
878.4 |
|
|
$ |
528.6 |
|
|
$ |
128.9 |
|
|
$ |
168.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
7.26 |
|
|
$ |
2.58 |
|
|
$ |
1.57 |
|
|
$ |
0.52 |
|
|
$ |
0.67 |
|
Diluted |
|
|
7.21 |
|
|
|
2.56 |
|
|
|
1.57 |
|
|
|
0.52 |
|
|
|
0.67 |
|
Dividends |
|
|
0.52 |
|
|
|
0.475 |
|
|
|
0.46 |
|
|
|
0.46 |
|
|
|
0.46 |
|
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, cash equivalents and short-term investments |
|
$ |
1,103.7 |
|
|
$ |
774.0 |
|
|
$ |
319.0 |
|
|
$ |
98.4 |
|
|
$ |
143.9 |
|
Working capital |
|
|
3,345.9 |
|
|
|
2,479.4 |
|
|
|
1,738.3 |
|
|
|
1,210.5 |
|
|
|
1,498.6 |
|
Total assets |
|
|
8,705.7 |
|
|
|
7,807.4 |
|
|
|
6,821.3 |
|
|
|
6,416.5 |
|
|
|
6,499.7 |
|
Long-term debt |
|
|
1,073.8 |
|
|
|
1,078.0 |
|
|
|
1,086.3 |
|
|
|
1,133.0 |
|
|
|
1,424.3 |
|
Stockholders equity |
|
|
5,242.9 |
|
|
|
4,697.8 |
|
|
|
3,895.4 |
|
|
|
3,350.4 |
|
|
|
3,397.2 |
|
NOTES TO SELECTED FINANCIAL DATA
(1) |
|
Discontinued operations. The selected financial data includes reclassifications to reflect
Baker Supply Products Division, Baker Hughes Mining Tools, BIRD Machine, EIMCO Process
Equipment and our oil producing operations in West Africa as discontinued operations. In
2003, we sold our interest in our oil producing operations in West Africa and in 2002, we sold
EIMCO Process Equipment. See Note 2 of the Notes to Consolidated Financial Statements in Item
8 herein for additional information regarding discontinued operations. |
|
(2) |
|
Equity in income (loss) of affiliates and impairment of investment in affiliate. In 2003, we
recorded $135.7 million in equity in income (loss) of affiliates for our share of $452.0
million of certain impairment and restructuring charges taken by WesternGeco, a seismic
venture in which we had a 30% interest. The charges related to the impairment of
WesternGecos multiclient seismic library and rationalization of WesternGecos marine seismic
fleet. In addition, as a result of the continued weakness in the seismic industry, we
evaluated the value of our investment in WesternGeco and recorded an impairment loss of $45.3
million in 2003 to write-down the investment to its fair value. In 2002, included in equity
in income (loss) of affiliates is $90.2 million for our share of a $300.7 million
restructuring charge related to WesternGecos impairment of assets, reductions in workforce,
closing certain operations and reducing its marine seismic fleet. In April 2006, we sold our
30% interest in WesternGeco. |
23
(3) |
|
Restructuring charge reversals. In 2000, our Board of Directors approved a plan to
substantially exit the oil and natural gas exploration business and recorded a restructuring
charge of $29.5 million. Included in the restructuring charge was $1.1 million for a
contractual obligation related to an oil and natural gas property in Angola. The property was
sold in 2003, and we reversed the liability related to this contractual obligation. |
|
(4) |
|
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, to Schlumberger for $2.4
billion. We recorded a pre-tax gain of $1,743.5 million on the sale. See Note 5 of the Notes
to Consolidated Financial Statements in Item 8 herein for additional information regarding
this sale. |
|
(5) |
|
Cumulative effect of accounting change. In 2005, we adopted Financial Accounting Standards
Board (FASB) Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement
Obligations. In 2003, we adopted Statement of Financial Accounting Standards (SFAS) No.
143, Accounting for Asset Retirement Obligations. In 2002, we adopted SFAS No. 142, Goodwill
and Other Intangible Assets. |
24
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
Organization
We are a leading provider of drilling, formation evaluation, completion and production
products and services to the worldwide oil and natural gas industry. We report our results under
three segments Drilling and Evaluation, Completion and Production and WesternGeco.
The Drilling and Evaluation segment and the Completion and Production segment are aligned by
product line based upon the types of products and services provided to our customers and upon the
business characteristics of the divisions during business cycles.
|
|
|
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. The Drilling and Evaluation
segment provides products and services used to drill and evaluate oil and natural gas
wells. |
|
|
|
|
The Completion and Production segment consists of the Baker Oil Tools (workover, fishing
and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift
(electric submersible pumps and progressing cavity pumps) divisions. The Completion and
Production segment also includes our ProductionQuest (formerly Production Optimization)
business unit. 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 WesternGeco segment consisted of 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. We recorded a pre-tax gain of $1,743.5
million ($1,035.2 million, net of tax).
The business operations of our divisions are organized around four primary geographic regions:
North America; Latin America; Middle East and Asia Pacific; and Europe, Africa, Russia and the
Caspian. 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, marketing 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 the customer, improving
our customer relationships and allowing us to react more quickly to local market conditions and
needs.
Our corporate headquarters are in Houston, Texas, and we have significant manufacturing
operations in various countries, including, but not limited to, the United States (Texas, Oklahoma
and Louisiana), the U.K. (Aberdeen, East Kilbride and Belfast), Germany (Celle), and Venezuela
(Maracaibo). We operate in over 90 countries around the world and employ approximately 34,600
employees about one-half of which work outside the U.S.
During 2006, the Baker Hughes worldwide rig count continued to increase, as oil and natural
gas companies around the world recognized the need to build productive capacity to meet the growing
demand for hydrocarbons and to offset depletion of existing developed reserves. Oil and natural
gas prices were at historic highs in 2006, reflecting continued strong demand and relatively low
spare productive capacity. We reported revenues of $9,027.4 million for 2006, a 25.6% increase
compared with 2005, exceeding the 13.2% increase in the worldwide average rig count for 2006
compared with 2005. In addition to the growth in our revenues from increased activity, our
revenues were impacted by pricing improvements and changes in market share in certain product
lines. Net income for 2006 was $2,419.0 million, which includes the $1,035.2 million after-tax
gain on the sale of our interest in WesternGeco, compared with $878.4 million in 2005.
|
|
|
North American revenues increased 31.2% in 2006 compared with 2005, while the rig count
increased 15.3% for 2006 compared with 2005, driven primarily by land-based drilling for
natural gas. In 2005, hurricane-related disruptions negatively impacted our revenues from
the U.S. offshore market by approximately $68.0 million. There were no significant
hurricane disruptions in 2006. |
25
|
|
|
Latin American revenues increased 15.3% in 2006 compared with 2005, while the rig count
increased 2.5% for 2006 compared with 2005. |
|
|
|
|
Europe, Africa, Russia and the Caspian revenues increased 22.8% in 2006 compared with
2005. Growth in revenues from Europe and Africa exceeded the increase in the rig counts
for both regions for the comparable periods. |
|
|
|
|
Middle East and Asia Pacific revenues were up 22.9% in 2006 compared with 2005. Revenue
from the Middle East was up 27.4% compared to a rig count which increased 25.3% and Asia
Pacific revenue was up 18.6% compared to a rig count which increased 1.3%. |
The customers for our products and services include the super-major and major integrated oil
and natural gas companies, independent oil and natural gas companies and state-owned national oil
companies (NOCs). Our ability to compete in the oilfield services market is dependent on our
ability to differentiate our product and service offerings by technology, service and the price
paid for the value we deliver.
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 forecasts of future oil and natural gas
prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas
production. During 2006, our customers spending directed to both worldwide oil and North American
natural gas projects increased compared with 2005. The increase in spending was driven by the
multi-year requirement to find, develop and produce more hydrocarbons to meet the growth in demand,
offset production declines, increase inventory levels and increase spare productive capacity.
Additionally, the increase was supported by historically high oil and natural gas prices.
The critical success factors for our business are embodied in our long-term strategy, which we
call our Strategic Framework. This strategy includes the development and maintenance of a high
performance culture founded on our Core Values; our product line focused organization and our focus
on Best-in-Class opportunities; maintaining our financial flexibility and financial discipline; and
execution of our strategies for product development and commercialization, manufacturing quality
and service quality.
Our ongoing effort to develop and maintain a high performance culture starts with our Core
Values of Integrity, Teamwork, Performance and Learning. We employ succession planning efforts to
develop leaders across all our businesses that embody these Core Values and represent the diversity
of our customer base. We hire and train employees from around the world to ensure that we have a
well-trained workforce in place to support our business plans.
Our focus on Best-in-Class opportunities starts with our product line focused organization
structure. We believe that through our product line focused divisions, we develop the technologies
that deliver Best-in-Class value to our customers. As an enterprise, we are also focused on those
markets that we believe provide Best-in-Class opportunities for growth. Our management team has
identified markets for immediate focus including the Middle East, Russia and the Caspian region,
India and NOCs.
Our focus on financial discipline is the backbone of our effort to deliver differential growth
at superior margins while earning an acceptable return on our investments throughout the business
cycle. Investments are given priority and funded depending on their ability to provide
risk-adjusted returns in excess of our cost of capital. Our effort to obtain the best price for
our products and services begins with our approach to capital discipline. Over the past few years,
we have invested for growth in our business, repaid debt, paid dividends and repurchased stock, and
we expect to maintain the financial flexibility needed to undertake such activities in the future.
The last element of our Strategic Framework focuses on our ability to identify, develop and
commercialize new products and services that will lead to differential growth at superior margins
in our business. The effort extends to every phase of our operations, including continuous
improvement programs in our manufacturing facilities and field operations that support our goal of
flawless execution at the well site.
The execution of our 2007 business plan and the ability to meet our 2007 financial objectives
are dependent on a number of factors. Foremost is the overall strength of the global oilfield
services market and, in particular, the strength of the North American natural gas driven oilfield
service market. Other factors include, but are not limited to, our ability to: recruit, train and
retain the skilled and diverse workforce necessary to meet our business needs; realize price
increases commensurate with the value we provide to our customers and in excess of the increase in
raw material and labor costs; expand our business in areas that are growing rapidly with customers
whose spending is expected to increase substantially (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 increasing raw material and component costs (especially steel alloys, copper, carbide,
chemicals and electronic components); continue to make ongoing improvements in the
26
productivity of our manufacturing organization and manage our spending in the North American
market depending on the relative strength or weakness of this market.
For a full discussion of risk factors and forward-looking statements, please see 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.
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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Oil prices ($/Bbl) |
|
$ |
66.09 |
|
|
$ |
56.59 |
|
|
$ |
41.51 |
|
Natural gas prices ($/mmBtu) * |
|
|
6.73 |
|
|
|
8.66 |
|
|
|
5.90 |
|
|
|
|
* |
|
In late September 2005, Hurricane Rita damaged natural gas processing facilities in Henry,
Louisiana (Henry Hub) and the New York Mercantile Exchange declared force majeure on its
Henry Hub natural gas contracts. As a result, the average natural gas prices for 2005 exclude
price data for September 22, 2005 through October 6, 2005 when there was insufficient activity
to determine a spot price. |
Oil prices averaged a nominal historic high of $66.09/Bbl for the year 2006. Prices reached
a high of $77/Bbl in July 2006 before declining to a low of $56/Bbl in late November on concerns
of slowing worldwide demand growth. In response to production cuts announced by OPEC in the fourth
quarter, prices recovered, ending the year slightly above $61/Bbl. Throughout the year, worldwide
demand for hydrocarbons was driven by worldwide economic growth, which was particularly strong in
China and developing Asia. Worldwide spare productive capacity remained at historically low
levels, and the potential for supply disruptions contributed to price volatility.
Natural gas prices averaged $6.73/mmBtu for the year 2006. In early January 2006, a tight
balance between supply and demand resulted in gas prices of just under $10/mmBtu. However, a
warmer than normal 2005/2006 winter required lower withdrawals of gas in storage to meet heating
demand, and the 2006 injection season began with record levels of natural gas in storage.
Throughout the year, inventories continued to increase to historically high levels. In response,
natural gas prices dropped below $4/mmBtu in late September. Prices rebounded in November on
expectations of cooler weather, before moderating again and ending the year under $6/mmBtu.
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 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
27
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005(1) |
|
2004(1) |
|
U.S. land and inland waters |
|
|
1,559 |
|
|
|
1,290 |
|
|
|
1,095 |
|
U.S. offshore |
|
|
90 |
|
|
|
93 |
|
|
|
97 |
|
Canada |
|
|
471 |
|
|
|
455 |
|
|
|
365 |
|
|
North America |
|
|
2,120 |
|
|
|
1,838 |
|
|
|
1,557 |
|
|
Latin America |
|
|
324 |
|
|
|
316 |
|
|
|
290 |
|
North Sea |
|
|
49 |
|
|
|
43 |
|
|
|
39 |
|
Other Europe |
|
|
28 |
|
|
|
27 |
|
|
|
31 |
|
Africa |
|
|
58 |
|
|
|
50 |
|
|
|
49 |
|
Middle East |
|
|
238 |
|
|
|
190 |
|
|
|
175 |
|
Asia Pacific |
|
|
228 |
|
|
|
225 |
|
|
|
197 |
|
|
Outside North America |
|
|
925 |
|
|
|
851 |
|
|
|
781 |
|
|
Worldwide |
|
|
3,045 |
|
|
|
2,689 |
|
|
|
2,338 |
|
|
U.S. Workover Rigs |
|
|
1,572 |
|
|
|
1,356 |
|
|
|
1,235 |
|
|
|
|
|
(1) |
|
Restated to exclude rig counts for Iran and Sudan, which counts were discontinued as
of December 31, 2005. |
The U.S. land and inland waters rig count increased 20.9% in 2006 compared with 2005, due to
the increased natural gas drilling activity. The U.S. offshore rig count decreased 3.2% in 2006
compared with 2005, reflecting the activity disruptions caused by hurricanes in the Gulf of Mexico
in the third quarter of 2005. The Canadian rig count increased 3.5% over 2005 levels due to the
higher natural gas drilling activity.
Outside North America, the rig count increased 8.7% in 2006 compared with 2005. The rig count
in Latin America increased 2.5% in 2006 compared with 2005, driven primarily by activity increases
in Venezuela, Colombia and Brazil. The North Sea rig count increased 14.0% in 2006 compared with
2005. The rig count in Africa increased by 16.0% in 2006 compared with 2005. Activity in 2006 in
the Middle East increased 25.3% compared with 2005, driven primarily by activity increases in Saudi
Arabia, Egypt, Pakistan and Yemen. The rig count in the Asia Pacific region was up 1.3% in 2006
compared with 2005, primarily due to activity increases in India, Indonesia, offshore China and
Thailand.
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 and drilling activity.
Our outlook is based upon our expectations for customer spending. Our expectations for
customer spending are in turn driven by our perception of industry expectations for energy prices
and their likely impact on customer capital and operating budgets. Our forecasts are based on
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).
Oil - In its January 2007 STEO, the DOE forecasted oil prices to average $64/Bbl in 2007. The
DOE has forecasted a high case of approximately $75/Bbl and a low case of approximately $55/Bbl.
The DOE expects oil prices to be within this band 95% of the time. While both inventories and
spare productive capacity have increased recently, the lack of spare productive capacity, which
buffers the market from supply disruptions, remains relatively low and is an indicator that supply
and demand remain relatively tightly balanced.
28
The increase in spare productive capacity has been and will be driven by planned cuts in OPEC
production which are aimed at supporting near-term oil prices while allowing for non-OPEC
production increases.
We believe that the DOEs forecasts are similar to the forecasts our customers are using to
plan their current spending levels and, with prices averaging between $55/Bbl and $75/Bbl, our
customers will continue to execute their capital budgets as planned. Our customers are more likely
to reduce their capital budgets if the oil price were expected to trade below $55/Bbl for an
extended period of time. The risks to oil prices falling significantly below $55/Bbl include (1) a
significant economic recession in either the US and/or China; (2) increases in Russian oil exports
or 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 spare
productive capacity and higher oil inventory levels or decreased demand. If prices were to rise
significantly above $75/Bbl there is a risk that the high energy price environment could destroy
demand and significantly slow economic growth. If economic growth were to slow, our customers
would likely decrease their capital spending from current levels. The primary risk of oil prices
exceeding $75/Bbl is a supply disruption in a major oil exporting country including Iran, Saudi
Arabia, Iraq, Venezuela, Nigeria or Norway.
Natural Gas - In its January 2007 STEO, the DOE forecasted that natural gas prices are
expected to average $7.05/mmBtu in 2007 with monthly averages varying between $6.40/mmBtu and
$8.70/mmBtu depending on seasonality. The DOE also publishes a high and low case and expects gas
to trade between these two cases 95% of the time. The low case varies between $4.10/mmBtu and
$5.40/mmBtu, depending on seasonality, and the high case varies between $8.60/mmBtu and
$12.90/mmBtu, depending on seasonality. Prices are expected to remain volatile through 2007 with
weather-driven demand and storage levels playing significant roles in determining prices.
If weather-dependent demand is strong enough to bring storage in-line with historical norms,
we expect natural gas to trade in the upper half of the DOEs forecast range. If weather-related
demand is insufficient to bring storage in-line with historic norms, we believe that natural gas
prices could approach the bottom of the DOEs forecast range. Based on industry data regarding
decline rates, we believe that a significant reduction in drilling activity would result in
decreased production within one or two quarters helping to rebalance supply and demand quickly and
prices would move from the bottom of the DOEs range to the middle or top of the range. We believe
that our customers forecasts are similar to the DOEs and that they recognize that the long-term
positive fundamentals for natural gas remain intact.
Customer Spending - Based upon our discussions with major customers, review of published
industry reports and our outlook for oil and natural gas prices described above, anticipated
customer spending trends are as follows:
|
|
|
Outside North America Customer spending, primarily directed at developing oil supplies,
is expected to increase approximately 17% to 19% in 2007 compared with 2006. |
|
|
|
|
North America Customer spending in North America, primarily towards developing natural
gas supplies, is expected to remain uncertain until our customers analyze end of winter
natural gas storage levels. |
Drilling Activity - Based upon our outlook for oil and natural gas prices and customer
spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig
count, is as follows:
|
|
|
Drilling activity outside of North America is expected to increase approximately 9% to 11% in 2007 compared with 2006. |
|
|
|
|
Drilling activity in North America is dependent upon our customers assessment of end of winter natural gas storage levels. |
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.
BUSINESS 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.
29
In our outlook for 2007, we took into account the factors described herein.
In 2006, 2005 and 2004, revenues outside North America were 55.7%, 57.6% and 58.5% of total
revenues, respectively. In 2007, we expect revenues outside North America to increase
approximately 17% to 19% compared with 2006, continuing the multi-year trend of growth in customer
spending. Spending on large projects by NOCs is expected to reflect established seasonality
trends, resulting in softer revenues in the first half of the year and stronger revenues in the
second half. In addition, customer spending could be affected by weather-related reductions in the
North Sea in the first and second quarters of 2007. The Middle East, Africa and Latin America
regions are expected to grow significantly in 2007 compared with 2006. Our expectations for
spending and revenue growth could decrease if there are disruptions in key oil and natural gas
production markets, such as Venezuela or Nigeria. Our assumptions regarding overall growth in
customer spending outside of North America assume strong economic growth in the United States,
China and the balance of the world outside of North America, resulting in an average oil price
exceeding $50/Bbl. Pricing improvement in 2007 is expected to contribute about one-half of the
contribution it made in 2006 compared to 2005. In the first quarter of 2007, earnings per diluted
share are expected to be in the range of
$1.08 to $1.10 per diluted share.
In 2006, 2005 and 2004, North American revenues were 44.3%, 42.4%, and 41.5% of total
revenues, respectively. Revenue growth in 2007 from North America remains uncertain given its
dependence on the impact of weather-driven demand on natural gas storage levels.
In 2006, WesternGeco contributed $58.7 million of equity in income of affiliates compared with
$96.7 million of equity in income of affiliates in 2005. We sold our 30% interest in WesternGeco
in April of 2006.
Other factors that could have a significant positive impact on profitability include:
increasing prices for our products and services; lower than expected raw material and labor costs;
and/or higher than planned activity. Conversely, less than expected price increases or 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 improve pricing is
dependent on demand for our products and services and our competitors strategies of managing
capacity. While the commercial introduction of new technology is an important factor in realizing
pricing improvement, without capital discipline throughout the industry as a whole, meaningful
improvements in our prices are not likely to be realized.
We do business in approximately 90 countries including over one-half of the 30 countries
having the lowest scores, which indicates high levels of corruption, in Transparency
Internationals Corruption Perception Index (CPI) survey for 2006. We devote significant
resources to the development, maintenance and enforcement of our Business Code of Conduct policy,
our Foreign Corrupt Practices Act (the FCPA) policy, 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. In addition, U.S. government agencies and
authorities are conducting investigations into allegations of potential violations of laws.
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 could limit
our ability to do business 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 laws and regulations and our Business Code of Conduct. In the
third quarter of 2005, our independent foreign subsidiaries initiated a process to prohibit any
business activity that directly or indirectly involves or facilitates transactions in Iran, Sudan
or with their governments, including government-controlled companies operating outside of these
countries. Implementation of this process was substantially completed as of December 31, 2006 and
did not have a material impact on our consolidated financial statements.
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, both contained herein. This list of risk factors is not intended to be all
inclusive.
30
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. 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, 2006 and 2005, allowance for doubtful
accounts totaled $50.5 million, or 2.4%, and $51.4 million, or 3.0%, 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 $2.5 million in 2006.
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, 2006
and 2005, inventory reserves totaled $211.7 million, or 12.2%, and $201.3 million, or 15.2%, 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, either adverse or positive, 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 $10.6 million in 2006.
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; however, based upon
our evaluation of the current business climate in which we operate, we do not currently anticipate
that any significant asset impairment losses will be necessary in the foreseeable future.
31
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. 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. Although we have
provided for the taxes that we believe will ultimately be payable as a result of these assessments,
the aggregate assessments are approximately $36.2 million in excess of the taxes provided for in
our consolidated financial statements.
In addition to the aforementioned assessments that have been received from various tax
authorities, we frequently provide for taxes in situations where assessments have not been
received. When we consider it probable that the taxes ultimately payable will exceed the amounts
reflected in filed tax returns, we provide such additional taxes under the guidance in Statement of
Financial Accounting Standards (SFAS) No. 5, Accounting for Contingencies. Future events such as
changes in the facts or tax law, judicial decisions regarding the application of existing law or a
favorable audit outcome may later indicate the assertion of additional taxes is no longer probable.
In that circumstance, it is possible that taxes previously provided would be released.
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
32
value of benefit obligations and increases plan expenses. We used a discount rate of 5.5% in
2006, 6.0% in 2005 and 6.3% in 2004 to determine plan expenses. A 50 basis point reduction in the
discount rate would have had an impact on income from continuing operations before income taxes of
approximately $1.5 million in 2006.
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 2006, 2005 and 2004. A 50 basis point reduction in the expected rate of
return on assets of our principal plans would have had an impact on income from continuing
operations before income taxes of approximately $2.0 million in 2006.
DISCONTINUED OPERATIONS
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 $42.5 million. We recorded a gain on the sale of $19.2 million, net of tax of $11.0
million, which consisted of an after-tax gain on the disposal of $16.9 million and $2.3 million
related to the recognition of the cumulative foreign currency translation adjustments into
earnings.
In September 2004, we completed the sale of Baker Hughes Mining Tools (BHMT), a product line
group within the Drilling and Evaluation segment that manufactured rotary drill bits used in the
mining industry, for $31.5 million. We recorded a gain on the sale of $0.2 million, net of tax of
$3.6 million, which consisted of an after-tax gain on the disposal of $6.8 million offset by a loss
of $6.6 million related to the recognition of the cumulative foreign currency translation
adjustments into earnings.
In January 2004, we completed the sale of BIRD Machine (BIRD) and recorded a loss on the
sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which were subject
to post-closing adjustments to the purchase price, and retained certain accounts receivable,
inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8
million to the buyer in settlement of the final purchase price adjustments. The adjustments were
the result of changes in the value of assets sold to and liabilities assumed by the buyer between
the date the initial sales price was negotiated and the closing of the sale.
We have reclassified the consolidated financial statements for all prior periods presented to
reflect these operations as discontinued. See Note 2 of the Notes to Consolidated Financial
Statements in Item 8 herein for additional information regarding discontinued operations.
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 for 2006, 2005 and 2004 (dollar amounts in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
$ |
|
% |
|
$ |
|
% |
|
$ |
|
% |
Revenues |
|
$ |
9,027.4 |
|
|
|
100.0 |
% |
|
$ |
7,185.5 |
|
|
|
100.0 |
% |
|
$ |
6,079.6 |
|
|
|
100.0 |
% |
Cost of revenues |
|
|
5,443.5 |
|
|
|
60.3 |
% |
|
|
4,642.9 |
|
|
|
64.6 |
% |
|
|
4,079.3 |
|
|
|
67.1 |
% |
Research and engineering |
|
|
338.9 |
|
|
|
3.8 |
% |
|
|
299.6 |
|
|
|
4.2 |
% |
|
|
271.7 |
|
|
|
4.5 |
% |
Selling, general and administrative |
|
|
1,310.7 |
|
|
|
14.5 |
% |
|
|
1,009.6 |
|
|
|
14.1 |
% |
|
|
912.2 |
|
|
|
15.0 |
% |
Revenues
Revenues for 2006 increased 25.6% compared with 2005, primarily due to increases in activity,
as evidenced by a 13.2% increase in the worldwide average rig count, pricing improvements between
seven and nine percent, introduction of new products and net
33
increases or decreases in market share in selected product lines and geographic areas.
Revenues in North America, which accounted for 44.3% of total revenues, increased 31.2% for 2006
compared with 2005. This increase reflects a continued broad based increase in drilling activity
in the U.S., as evidenced by the 15.3% increase in the North American rig count, with activity
dominated by land-based gas-directed drilling. Revenues outside North America, which accounted for
55.7% of total revenues, increased 21.5% for 2006 compared with 2005. This increase reflects the
improvement in international drilling activity, as evidenced by the 8.7% increase in the rig count
outside North America, particularly in the Middle East, Africa and the North Sea, coupled with
pricing improvements in certain markets and product lines.
Revenues for 2005 increased 18.2% compared with 2004, primarily due to increases in activity,
as evidenced by a 14.8% increase in the worldwide rig count, pricing improvements of between four
and six percent and increases 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 in 2005.
Revenues in North America, which accounted for 42.4% of total revenues, increased 20.9% for 2005
compared with 2004, despite the unfavorable impact on our U.S. offshore revenues of approximately
$68.0 million from hurricane-related disruptions. This increase reflects increased activity in the
U.S., as evidenced by the 18.0% increase in the North American rig count, with activity dominated
by land-based gas-directed drilling. Revenues outside North America, which accounted for 57.6% of
total revenues, increased 16.3% for 2005 compared with 2004. This increase reflects the
improvement in international drilling activity in 2005, as evidenced by the 8.6% increase in the
rig count outside North America, particularly in Latin America, the Middle East and Asia Pacific,
coupled with price increases in certain markets and product lines.
Cost of Revenues
Cost of revenues for 2006 increased 17.2% compared with 2005. Cost of revenues as a
percentage of revenues was 60.3% and 64.6% for 2006 and 2005, respectively. The decrease in cost
of revenues as a percentage of consolidated revenues was primarily the result of overall average
price increases between seven and nine percent and continued high utilization of our rental tool
fleet and personnel. A change in the geographic and product mix from the sale of our products and
services also contributed to the decrease in the cost of revenues as a percentage of revenues.
This increase was partially offset by higher raw material costs and employee compensation costs.
In addition to these factors, during the fourth quarter of 2006, we revised the accounting
procedures related to certain inventory for our Baker Atlas division resulting in a one time
reduction in cost of revenues in 2006 of approximately $21.2 million.
Cost of revenues for 2005 increased 13.8% compared with 2004. Cost of revenues as a
percentage of revenues was 64.6% and 67.1% for 2005 and 2004, respectively. The decrease in cost
of revenues as a percentage of consolidated revenues was primarily the result of overall average
price increases between four and six percent and very high utilization of our rental tool fleet and
personnel. This increase was partially offset by higher raw material costs and employee
compensation expenses.
Research and Engineering
Research and engineering expenses increased 13.1% in 2006 compared with 2005 and 10.3% in 2005
compared with 2004. The increase in both years reflect our commitment in developing and
commercializing new technologies as well as investing in our core product offerings.
Selling, General and Administrative
Selling, general and administrative expenses increased 29.8% in 2006 compared with 2005. The
increase corresponds with increased activity and resulted primarily from higher marketing and
employee compensation costs, including stock-based compensation which increased $26.0 million due
to the adoption of Statement of Financial Accounting Standard No. 123(R) Shared Based Payment,
using the modified prospective application method. The increase also results from the financial
charge of $46.1 million recorded in the fourth quarter of 2006 in connection with the settlement
negotiations with the SEC and DOJ.
Selling, general and administrative expenses increased 10.7% in 2005 compared with 2004. The
increase corresponds with increased activity and resulted primarily from higher marketing and
employee compensation expenses.
Equity in Income of Affiliates
Equity in income of affiliates decreased $39.7 million in 2006 compared with 2005. The
decrease in equity in income of affiliates for 2006 is primarily due to the sale of our 30%
interest in WesternGeco, our most significant equity method investment, on April 28, 2006.
34
Equity in income of affiliates increased $63.8 million in 2005 compared with 2004. The
increase is primarily due to the increase in equity in income of WesternGeco. In 2005,
WesternGecos revenue and profitability continued to improve as a result of ongoing favorable
market conditions in the seismic industry.
Gain on Sale of Interest in Affiliate
On April 28, 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash. We
recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax).
Interest Expense and Interest and Dividend Income
Interest expense decreased $3.4 million in 2006 compared with 2005. The decrease was
primarily due to lower total debt levels. Interest and dividend income in 2006 increased $49.5
million over 2005, primarily due to the interest and dividends earned on the invested cash received
from the sale of our interest in WesternGeco.
Interest expense decreased $11.3 million in 2005 compared with 2004. The decrease was
primarily due to lower total debt levels partially offset by the impact of the interest rate swap
agreement that was in place from April 2004 through June 2005. The lower total debt levels were a
result of the repayment of $350.0 million of long-term debt in the second quarter of 2004.
Interest and dividend income in 2005 increased $11.2 million over 2004, due to significantly higher
cash balances and short-term investments during the year resulting primarily from higher cash flows
from operations.
Income Taxes
Our effective tax rate in 2006 is 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 $708.3 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. In 2005, we reflected a $10.6 million
reduction to tax expense attributable to the recognition of a deferred tax asset associated with
our supplemental retirement plan (SRP).
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.
Cumulative Effect of Accounting Change
On December 31, 2005, we adopted Financial Accounting Standards Board (FASB) Interpretation
No. 47, Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term
conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an asset retirement activity in which the
timing and/or method of settlement are conditional on a future event that may or may not be within
the control of the entity. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax
of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated
statement of operations. In conjunction with the adoption, we recorded conditional asset
retirement obligations of $1.6 million as the fair value of the costs associated with the special
handling of asbestos related materials in certain facilities.
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain adequate financial resources and access
to additional liquidity. During 2006, cash flows from operations and proceeds from the sale of our
interest in WesternGeco were the principal sources of funding. We anticipate that cash flows from
operations will be sufficient to fund our liquidity needs in 2007. We also have a $500.0 million
committed revolving credit facility that provides back-up liquidity in the event an unanticipated
and significant demand on cash flows could not be funded by operations.
Our capital planning process is focused on utilizing cash flows generated from operations in
ways that enhance the value of our Company. In 2006, we used cash for a variety of activities
including working capital needs, payment of dividends, repurchase of common stock and capital
expenditures.
35
Cash Flows
Cash flows provided (used) by continuing operations by type of activity were as follows for
the years ended December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
Operating activities |
|
$ |
589.7 |
|
|
$ |
949.6 |
|
|
$ |
781.8 |
|
Investing activities |
|
|
1,376.2 |
|
|
|
(465.3 |
) |
|
|
(196.3 |
) |
Financing activities |
|
|
(1,926.4 |
) |
|
|
(108.1 |
) |
|
|
(352.2 |
) |
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 $589.7 million for the
year ended December 31, 2006 compared with $949.6 million for the year ended December 31, 2005.
Cash flows from operating activities for 2006 were reduced by $555.1 million of 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 were $1,144.8 million, an increase of $195.2
million from the prior year. This increase is primarily due to an increase in income from
continuing operations partially offset by a change in net operating assets and liabilities that
used cash flows. Cash flows from operating activities, excluding the WesternGeco transaction in
2006, have been steadily increasing over the last three years and we expect this trend to continue
in 2007.
The underlying drivers of the changes in operating assets and liabilities are as follows:
|
|
|
An increase in accounts receivable used $316.4 million in cash in 2006 compared with
using $329.4 million in cash in 2005. This was due to an increase in revenues partially
offset by a decrease in the quarterly days sales outstanding (defined as the average number
of days our net trade receivables are outstanding based on quarterly revenues) of
approximately two days. |
|
|
|
|
A build up in inventory in anticipation of and related to increased activity used $364.9
million in cash in 2006 compared with using $108.7 million in cash in 2005. |
|
|
|
|
An increase in accounts payable, accrued employee compensation and other accrued
liabilities provided $173.2 million in cash in 2006 compared with providing $214.7 million
in cash in 2005. This was due primarily to increased activity and increased employee
compensation accruals. |
Our contributions to our defined benefit pension plans in 2006 were approximately $34.0
million, a decrease of approximately $14.0 million compared to 2005, primarily due to reduced
contributions in 2006 in anticipation of the merger of two U.S. pension plans on January 1, 2007.
Cash flows from operating activities of continuing operations increased $167.8 million in 2005
compared with 2004. This increase was primarily due to an increase in income from continuing
operations of $349.1 million partially offset by a change in net operating assets and liabilities
that used $180.6 million more in cash flows during 2005 compared with 2004.
The underlying drivers of the changes in operating assets and liabilities are as follows:
|
|
|
An increase in accounts receivable used $329.4 million in cash in 2005 compared with
using $173.7 million in cash in 2004. This was due to an increase in revenues and an
increase in the quarterly days sales outstanding (defined as the average number of days our
net trade receivables are outstanding based on quarterly revenue) of approximately three
days. |
|
|
|
|
A build up in inventory in anticipation of and related to increased activity used $108.7
million in cash in 2005 compared with using $3.2 million in cash in 2004. |
|
|
|
|
An increase in accounts payable, accrued employee compensation and other accrued
liabilities provided $214.7 million in cash in 2005 compared with providing $175.6 million
in cash in 2004. This was due primarily to increased activity and increased employee
compensation accruals. |
36
Our contributions to our defined benefit pension plans in 2005 were approximately $48.0
million, a decrease of approximately $62.0 million compared to 2004. In 2004, management made the
decision to fund at higher levels to reduce the underfunded status of certain pension plans.
Investing Activities
Our principal recurring investing activity is the funding of capital expenditures to ensure
that we have the appropriate levels and types of rental tools in place to generate revenues from
operations. Expenditures for capital assets totaled $922.2 million, $478.3 million and $348.2
million for 2006, 2005 and 2004, respectively. The majority of these expenditures were for rental
tools, including wireline tools, and machinery and equipment. The increase in capital assets in
2006 is a result of increased demand for our products and services.
During 2006, we paid $66.2 million for acquisitions of businesses, net of cash acquired. In
the first quarter of 2006, we acquired Nova Technology Corporation (Nova) for $55.4 million, net
of cash acquired of $3.0 million, plus assumed debt. In the second and third quarters of 2006, we
made three acquisitions for $10.8 million, net of cash acquired of $0.7 million.
During 2005, we paid $46.8 million for acquisitions of businesses, net of cash acquired. In
December, we purchased Zeroth Technology Limited (Zertech) for $20.3 million. In November, we
paid $25.5 million, net of cash acquired of $1.7 million, for the remaining 50% interest in QuantX
Wellbore Instrumentation (QuantX). During 2005, we also made smaller acquisitions having an
aggregate purchase price of $1.0 million.
In 2004, we paid $6.6 million for acquisition of businesses, net of cash acquired. We
purchased the remaining 60% interest in Luna Energy L.L.C. (Luna), a venture we entered into in
2002, for $1.0 million. We also paid $5.6 million in settlement of the final purchase price
related to an acquisition completed in a prior year and invested an additional $7.1 million in
certain of our investments in affiliates.
During 2006, we purchased $3,882.9 million of and received proceeds of $3,606.2 million from
maturing auction rate securities, which are highly liquid, variable-rate debt securities. During
2005, we purchased $77.0 million of auction rate 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, creating short-term liquidity. These short-term investments are classified as
available-for-sale securities and are recorded at cost, which approximates market value.
Proceeds from disposal of assets were $135.4 million, $90.1 million and $106.9 million for
2006, 2005 and 2004, 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 and 2004 was $10.4 million and $12.2
million, respectively, related to the sale of certain real estate properties held for sale.
On April 28, 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash.
WesternGeco also made a cash distribution of $59.6 million prior to closing. In 2005, we received
distributions of $30.0 million from WesternGeco, which were recorded as a reduction in the carrying
value of our investment. We also received $13.3 million from Schlumberger related to the
WesternGeco true-up payment, of which $13.0 million was recorded as a reduction in the carrying
value of our investment and $0.3 million as interest income.
In 2006, we received $46.3 million in net proceeds from the sale of certain businesses and our
interest in an affiliate. Specifically, in March 2006, we completed the sale of Baker SPD and
received $42.5 million in proceeds, and we received $3.8 million from the release of the remaining
amount held in escrow related to our sale of Petreco International. In May 2005, we received $3.7
million from the initial release of this escrow.
In 2004, we received $58.7 million in net proceeds from the sale of certain businesses and our
interest in an affiliate. Specifically, in January 2004, we completed the sale of BIRD and
received $5.6 million in proceeds, which were subject to post-closing adjustments to the purchase
price. In June 2004, we made a net payment of $6.8 million to the buyer of BIRD in settlement of
the final purchase price adjustments. In February 2004, we completed the sale of our minority
interest in Petreco International, a venture we entered into in 2001, and received proceeds of
$35.8 million, of which $7.4 million was placed in escrow pending the outcome of potential
indemnification obligations pursuant to the sales agreement. In September 2004, we also completed
the sale of BHMT and received proceeds of $31.5 million.
We routinely evaluate potential acquisitions of businesses of third parties that may enhance
our current operations or expand our
37
operations into new markets or product lines. We may also from time to time sell business
operations that are not considered part of our core business.
Financing Activities
We had net (repayments) borrowings of commercial paper and other short-term debt of $(8.8)
million, $(71.1) million and $35.5 million in 2006, 2005 and 2004, respectively. In 2004, we
repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June
2004. These repayments were funded with cash on hand, cash flows from operations and the issuance
of commercial paper. Total debt outstanding at December 31, 2006 was $1,075.1 million, a decrease of $12.8 million
compared with December 31, 2005. The total debt to total capitalization (defined as total debt
plus stockholders equity) ratio was 0.17 at December 31, 2006 and 0.19 at December 31, 2005.
In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0
million associated with our 6.25% Notes due January 2009. The interest rate swap agreement was
designated and qualified as a fair value hedging instrument. Due to our outlook for interest
rates, we terminated the interest rate swap agreement in June 2005, which required us to make a
payment of $5.5 million. This amount was deferred and is being amortized as an increase to
interest expense over the remaining life of the underlying debt security.
We received proceeds of $92.5 million, $228.1 million and $115.9 million in 2006, 2005 and
2004, respectively, from the issuance of common stock through the exercise of stock options and the
employee stock purchase plan.
On October 27, 2005, the Board of Directors authorized us to repurchase up to $455.5 million
of common stock, which was in addition to the balance of $44.5 million remaining from the Board of
Directors September 2002 authorization, resulting in the authorization to repurchase up to a total
of $500.0 million of common stock. During 2005, we repurchased 1.7 million shares of our common
stock at an average price of $58.17 per share, for a total of $98.5 million. In April 2006, the
Board of Directors authorized the repurchase of an additional $1.8 billion of common stock. During
2006, we repurchased 24.3 million shares of our common stock at an average price of $76.50 per
share, for a total of $1,856.0 million. At December 31, 2006, we had authorization remaining to
repurchase up to a total of $345.5 million of our common stock.
We paid dividends of $172.6 million, $161.1 million and $153.6 million in 2006, 2005 and 2004,
respectively. Beginning in the fourth quarter of 2005 as authorized by our Board of Directors, we
increased our quarterly dividend to $0.13 per share, compared to $0.115 per share that was paid in
prior quarters.
Available Credit Facilities
At December 31, 2006, we had $1,057.8 million of credit facilities with commercial banks, of
which $500.0 million is a committed revolving credit facility (the facility) that expires in July
2011. The facility provides for up to two one-year extensions, subject to the approval and
acceptance by the lenders, among other conditions. In addition, the facility contains a provision
to allow for an increase in the facility amount of an additional $500.0 million, subject to the
approval and acceptance by the lenders, among other conditions. The facility contains certain
covenants which, among other things, require the maintenance of a funded indebtedness to total
capitalization ratio (a defined formula per the facility) of less than or equal to 0.60, 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 facility may be accelerated. Such events of
default include payment defaults to lenders under the facility, covenant defaults and other
customary defaults. At December 31, 2006, we were in compliance with all of the facility
covenants. There were no direct borrowings under the facility during the year ended December 31,
2006; however, to the extent we have outstanding commercial paper, our ability to borrow under the
facility is reduced. At December 31, 2006, we had no outstanding commercial paper.
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
facility that would accelerate the maturity of any borrowings under the facility. However, a
downgrade in our credit ratings could increase the cost of borrowings under the facility 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 facility.
We believe our credit ratings and relationships with major commercial and investment banks
would allow us to 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.
38
Cash Requirements
In 2007, we believe operating cash flows will provide us with sufficient capital resources and
liquidity to manage our working capital needs, meet contractual obligations, fund capital
expenditures, pay dividends, repurchase common stock and support the development of our short-term
and long-term operating strategies.
In 2007, we expect capital expenditures to be between $1.0 billion and $1.2 billion, excluding
acquisitions. The expenditures are expected to be used primarily for normal, recurring items
necessary to support the growth of our business and operations.
In 2007, we expect to make interest payments of between $73.0 million and $75.0 million. This
is based on our current expectations of debt levels during 2007.
We anticipate making income tax payments of between $875.0 million and $925.0 million in 2007.
As of December 31, 2006, we have authorization remaining to repurchase up to $345.5 million in
common stock. We may repurchase our common stock depending on market conditions, applicable legal
requirements, our liquidity and other considerations. We anticipate paying dividends of between
$165.0 million and $170.0 million in 2007; however, the Board of Directors can change the dividend
policy at anytime.
In the U.S., we merged two pension plans effective January 1, 2007, resulting in one
tax-qualified U.S. pension plan, the Baker Hughes Incorporated Pension Plan (BHIPP). As a result
of the merger of these plans, BHIPP is overfunded; therefore, we are not required nor do we intend
to make pension contributions to BHIPP in 2007, and we currently estimate that we will not be
required to make contributions to BHIPP for five to eight years thereafter. We do expect to
contribute between $2.0 million and $3.0 million to our nonqualified U.S. pension plans and between
$13.0 million and $15.0 million to the non-U.S. pension plans. We will also make benefit payments
related to postretirement welfare plans of between $13.0 million and $15.0 million, and we estimate
we will contribute between $115.0 million and $125.0 million to our defined contribution plans.
Other than as previously discussed, we do not believe there are any other material trends,
demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a
material impact on our financial condition and liquidity. Other than as previously discussed, we
currently have no information that would create a reasonable likelihood that the reported levels of
revenues and cash flows from operations in 2006 are not indicative of what we can expect in the
near term.
Contractual Obligations
In the table below, we set forth our contractual cash obligations as of December 31, 2006.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period |
|
|
|
|
|
|
Less Than |
|
2 3 |
|
4 5 |
|
More than |
(In millions) |
|
Total |
|
1 year |
|
Years |
|
Years |
|
5 Years |
|
Total debt (1) |
|
$ |
1,076.3 |
|
|
$ |
1.3 |
|
|
$ |
525.0 |
|
|
$ |
|
|
|
$ |
550.0 |
|
Estimated interest payments (2) |
|
|
924.0 |
|
|
|
72.6 |
|
|
|
129.1 |
|
|
|
80.6 |
|
|
|
641.7 |
|
Operating leases(3) |
|
|
368.2 |
|
|
|
82.0 |
|
|
|
98.2 |
|
|
|
50.1 |
|
|
|
137.9 |
|
Purchase obligations (4) |
|
|
253.7 |
|
|
|
240.5 |
|
|
|
13.2 |
|
|
|
|
|
|
|
|
|
Other long-term liabilities (5) |
|
|
102.7 |
|
|
|
26.3 |
|
|
|
61.5 |
|
|
|
10.1 |
|
|
|
4.8 |
|
|
Total |
|
$ |
2,724.9 |
|
|
$ |
422.7 |
|
|
$ |
827.0 |
|
|
$ |
140.8 |
|
|
$ |
1,334.4 |
|
|
|
|
|
(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 fixed rate
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
would change if we exercised these renewal options and if we entered into additional operating
lease agreements. |
39
|
|
|
(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, payments for various postretirement welfare benefit plans and
postemployment benefit plans and payments for deferred taxes and other tax liabilities. |
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 $376.9 million at December 31, 2006. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts of approximately $253.7 million at December 31, 2006. 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.
NEW ACCOUNTING STANDARDS
In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155,
Accounting for Certain Hybrid Financial Instruments an amendment of FASB Statements No. 133 and
No. 140 (SFAS 155). SFAS 155 amends SFAS 133, which required that a derivative embedded in a
host contract that does not meet the definition of a derivative be accounted for separately under
certain conditions. SFAS 155 is effective for all financial instruments acquired or issued (or
subject to a remeasurement event) following the start of an entitys first fiscal year beginning
after September 15, 2006. We adopted SFAS 155 on January 1, 2007, and there was no impact on our
consolidated financial statements.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting
for uncertainty in income taxes recognized in an entitys financial statements in accordance with
SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement
attribute for financial statement disclosure of tax positions taken or expected to be taken on a
tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted
FIN 48 on January 1, 2007. We currently estimate the cumulative effect of adopting FIN 48 to be a
reduction to consolidated retained earnings as of January 1, 2007 in the range of $45.0 million to
$60.0 million.
In September 2006, the FASB issued 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 is effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS 157 on
January 1, 2008, and have not yet determined the impact, if any, on our consolidated financial
statements.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plansan 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 will be adopted on December 31, 2008, as allowed under SFAS 158.
See Note 14 for the incremental effect of applying SFAS 158 on our consolidated balance sheet as
of December 31, 2006.
40
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin
108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements (SAB 108). SAB 108 requires that public companies utilize a
dual-approach to assessing the quantitative effects of financial misstatements. This dual
approach includes both an income statement focused assessment and a balance sheet focused
assessment. SAB 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB
108 on December 31, 2006, and there was no impact on our consolidated financial statements.
In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (FSP AUG AIR-1), which
addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use
of the accrue-in-advance method of accounting for planned major maintenance activities in annual
and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007, and we will
be applying the retrospective application for all financial statements presented. We currently do
not expect there to be a material impact on our consolidated financial statements as a result of
this adoption.
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 measure eligible 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 will adopt SFAS 159 on
January 1, 2008, and have not yet determined the impact, if any, on our consolidated financial
statements.
RELATED PARTY TRANSACTIONS
On April 28, 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash. We
recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, net of tax).
In November 2000, we entered into an agreement with WesternGeco, whereby WesternGeco subleases
a facility from us for a period of ten years at then current market rates. In 2006, we entered
into an extension of the sublease for five additional years with rent to be determined based on
market rates in 2010. During 2006, 2005 and 2004, we received payments of $5.6 million, $6.5
million and $5.5 million, respectively, from WesternGeco related to this lease.
During 2006 and 2005, we received distributions of $59.6 million and $30.0 million,
respectively, from WesternGeco, which were recorded as reductions in the carrying value of our
investment.
During 2005, we received $13.3 million from Schlumberger related to a true-up payment
associated with revenues earned by WesternGeco during the four year period ending November 2004
from each partys contributed multiclient seismic data libraries. We recorded $13.0 million as a
reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest
income. The income tax effect of $3.3 million related to this payment is included in our provision
for income taxes for the year ended December 31, 2005.
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,
final resolution of pending government investigations, 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
41
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.
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. 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 is 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, 2006 and at December 31, 2005, there were no interest rate swap agreements in
effect. Due to our outlook for interest rates, on June 2, 2005, we terminated the interest rate
swap agreement we had entered into in April 2004. This agreement had been designated and had
qualified as a fair value hedging instrument. Upon termination we were required to pay $5.5
million. This amount is being amortized as an increase to interest expense over the remaining life
of the underlying debt security, which matures in January 2009.
We had fixed rate debt aggregating $1,075.0 million at December 31, 2006 and 2005. 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, 2006 and 2005 (dollar amounts in
millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
Thereafter |
|
Total |
|
|
|
As of December 31, 2006: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1) (2) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
525.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
550.0 |
|
|
$ |
1,075.0 |
|
Weighted average
effective interest rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.23 |
%(3) |
|
|
|
|
|
|
|
|
|
|
7.55 |
% |
|
|
6.39 |
%(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2005: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1) (2) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
525.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
550.0 |
|
|
$ |
1,075.0 |
|
Weighted average
effective interest rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.19 |
%(3) |
|
|
|
|
|
|
|
|
|
|
7.55 |
% |
|
|
6.37 |
%(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 $1,169.7 million at December 31,
2006 and $1,223.7 million at December 31, 2005. |
|
(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 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 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.
At December 31, 2006, we had entered into several foreign currency forward contracts with
notional amounts aggregating $105.0
42
million to hedge exposure to currency fluctuations in various foreign currency payables and
receivables, including British Pound Sterling, Norwegian Krone, Euro, Indonesian Rupiah and
Brazilian Real. These contracts are designated and qualify as fair value hedging instruments.
Based on quoted market prices as of December 31, 2006 for contracts with similar terms and maturity
dates, we recorded a loss of $0.2 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 selling, general and administrative expense in the
consolidated statement of operations.
At December 31, 2005, we had entered into several foreign currency forward contracts with
notional amounts aggregating $65.0 million to hedge exposure to currency fluctuations in various
foreign currency payables and receivables, including British Pound Sterling, Norwegian Krone, Euro
and Brazilian Real. These contracts were designated and qualified as fair value hedging
instruments. Based on quoted market prices as of December 31, 2005 for contracts with similar
terms and maturity dates, we recorded a gain of $0.1 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 selling, general and
administrative expense in the 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 unlikely 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.
43
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, 2006. 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.
Our managements assessment of the effectiveness of our internal control over financial
reporting as of December 31, 2006 has been audited by Deloitte & Touche LLP, an independent
registered public accounting firm, as stated in their report which is included herein.
|
|
|
|
|
/s/ CHAD C. DEATON
|
|
/s/ PETER A. RAGAUSS
|
|
/s/ ALAN J. KEIFER |
|
|
|
|
|
Chad C. Deaton
Chairman and
Chief Executive Officer
|
|
Peter A. Ragauss
Senior Vice President and
Chief Financial Officer
|
|
Alan J. Keifer
Vice President and
Controller |
Houston, Texas
February 21, 2007
44
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
We have audited managements assessment, included in the accompanying Managements Report on
Internal Control Over Financial Reporting, that Baker Hughes Incorporated and subsidiaries (the
Company) maintained effective internal control over financial reporting as of December 31, 2006,
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. Our responsibility is to express an
opinion on managements assessment and an opinion on the effectiveness of the Companys internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions.
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, managements assessment that the Company maintained effective internal control
over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based
on the criteria established in Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of December 31,
2006, 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, 2006 of the Company and our report dated
February 21, 2007, 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 21, 2007
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 accompanying consolidated balance sheets of Baker Hughes Incorporated and
subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated
statements of operations, stockholders equity, and cash flows for each of the three years in the
period ended December 31, 2006. 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,
2006 and 2005, and the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2006, 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, presents
fairly, in all material respects, the information set forth therein.
As described in Note 4 and Note 14 to the consolidated financial statements: effective as of
January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123R,
which established new accounting and reporting standards for stock-based compensation; effective as
of December 31, 2006, the Company adopted SFAS No. 158, which established new accounting and
reporting standards for defined benefit pension and other post retirement plans.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Companys internal control over financial
reporting as of December 31, 2006, 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 21, 2007 expressed an unqualified opinion on managements assessment of the
effectiveness of the Companys internal control over financial reporting and an unqualified opinion
on the effectiveness of the Companys internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 21, 2007
46
Baker Hughes Incorporated
Consolidated Statements of Operations
(In millions, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
$ |
4,566.1 |
|
|
$ |
3,738.2 |
|
|
$ |
3,298.6 |
|
Services and rentals |
|
|
4,461.3 |
|
|
|
3,447.3 |
|
|
|
2,781.0 |
|
|
Total revenues |
|
|
9,027.4 |
|
|
|
7,185.5 |
|
|
|
6,079.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
2,714.3 |
|
|
|
2,303.9 |
|
|
|
2,086.0 |
|
Cost of services and rentals |
|
|
2,729.2 |
|
|
|
2,339.0 |
|
|
|
1,993.3 |
|
Research and engineering |
|
|
338.9 |
|
|
|
299.6 |
|
|
|
271.7 |
|
Selling, general and administrative |
|
|
1,310.7 |
|
|
|
1,009.6 |
|
|
|
912.2 |
|
|
Total costs and expenses |
|
|
7,093.1 |
|
|
|
5,952.1 |
|
|
|
5,263.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
1,934.3 |
|
|
|
1,233.4 |
|
|
|
816.4 |
|
Equity in income of affiliates |
|
|
60.4 |
|
|
|
100.1 |
|
|
|
36.3 |
|
Gain on sale of interest in affiliate |
|
|
1,743.5 |
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(68.9 |
) |
|
|
(72.3 |
) |
|
|
(83.6 |
) |
Interest and dividend income |
|
|
67.5 |
|
|
|
18.0 |
|
|
|
6.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes |
|
|
3,736.8 |
|
|
|
1,279.2 |
|
|
|
775.9 |
|
Income taxes |
|
|
(1,338.2 |
) |
|
|
(404.8 |
) |
|
|
(250.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
2,398.6 |
|
|
|
874.4 |
|
|
|
525.3 |
|
Income from discontinued operations, net of tax |
|
|
20.4 |
|
|
|
4.9 |
|
|
|
3.3 |
|
|
Income before cumulative effect of accounting change |
|
|
2,419.0 |
|
|
|
879.3 |
|
|
|
528.6 |
|
Cumulative effect of accounting change, net of tax |
|
|
|
|
|
|
(0.9 |
) |
|
|
|
|
|
Net income |
|
$ |
2,419.0 |
|
|
$ |
878.4 |
|
|
$ |
528.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
7.26 |
|
|
$ |
2.58 |
|
|
$ |
1.57 |
|
Income from discontinued operations |
|
|
0.06 |
|
|
|
0.01 |
|
|
|
0.01 |
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
7.32 |
|
|
$ |
2.59 |
|
|
$ |
1.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
7.21 |
|
|
$ |
2.56 |
|
|
$ |
1.57 |
|
Income from discontinued operations |
|
|
0.06 |
|
|
|
0.01 |
|
|
|
0.01 |
|
Cumulative effect of accounting change |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
7.27 |
|
|
$ |
2.57 |
|
|
$ |
1.58 |
|
|
See Notes to Consolidated Financial Statements
47
Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except par value)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2006 |
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
750.0 |
|
|
$ |
697.0 |
|
Short-term investments |
|
|
353.7 |
|
|
|
77.0 |
|
Accounts receivable less allowance for doubtful accounts: |
|
|
|
|
|
|
|
|
December 31, 2006, $50.5; December 31, 2005, $51.4 |
|
|
2,055.1 |
|
|
|
1,673.4 |
|
Inventories |
|
|
1,528.8 |
|
|
|
1,126.3 |
|
Deferred income taxes |
|
|
167.8 |
|
|
|
181.2 |
|
Other current assets |
|
|
112.4 |
|
|
|
68.6 |
|
Assets of discontinued operations |
|
|
|
|
|
|
16.6 |
|
|
Total current assets |
|
|
4,967.8 |
|
|
|
3,840.1 |
|
|
|
|
|
|
|
|
|
|
Investments in affiliates |
|
|
20.0 |
|
|
|
678.9 |
|
Property less accumulated depreciation: |
|
|
|
|
|
|
|
|
December 31, 2006, $2,713.4; December 31, 2005, $2,475.7 |
|
|
1,800.5 |
|
|
|
1,355.5 |
|
Goodwill |
|
|
1,347.0 |
|
|
|
1,315.8 |
|
Intangible assets less accumulated amortization: |
|
|
|
|
|
|
|
|
December 31, 2006, $102.3; December 31, 2005, $84.5 |
|
|
190.4 |
|
|
|
163.4 |
|
Other assets |
|
|
380.0 |
|
|
|
453.7 |
|
|
Total assets |
|
$ |
8,705.7 |
|
|
$ |
7,807.4 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
648.8 |
|
|
$ |
558.1 |
|
Short-term borrowings and current portion of long-term debt |
|
|
1.3 |
|
|
|
9.9 |
|
Accrued employee compensation |
|
|
484.2 |
|
|
|
424.5 |
|
Income taxes |
|
|
150.0 |
|
|
|
141.5 |
|
Other accrued liabilities |
|
|
337.6 |
|
|
|
222.9 |
|
Liabilities of discontinued operations |
|
|
|
|
|
|
3.8 |
|
|
Total current liabilities |
|
|
1,621.9 |
|
|
|
1,360.7 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
1,073.8 |
|
|
|
1,078.0 |
|
Deferred income taxes and other tax liabilities |
|
|
300.2 |
|
|
|
228.1 |
|
Liabilities for pensions and other postretirement benefits |
|
|
339.3 |
|
|
|
336.1 |
|
Other liabilities |
|
|
127.6 |
|
|
|
106.7 |
|
|
|
|
|
|
|
|
|
|
Stockholders Equity: |
|
|
|
|
|
|
|
|
Common stock, one dollar par value (shares authorized - 750.0;
issued and outstanding - 319.9 at December 31, 2006 and
341.5 at
December 31, 2005) |
|
|
319.9 |
|
|
|
341.5 |
|
Capital in excess of par value |
|
|
1,600.6 |
|
|
|
3,293.5 |
|
Retained earnings |
|
|
3,509.6 |
|
|
|
1,263.2 |
|
Accumulated other comprehensive loss |
|
|
(187.2 |
) |
|
|
(188.0 |
) |
Unearned compensation |
|
|
|
|
|
|
(12.4 |
) |
|
Total stockholders equity |
|
|
5,242.9 |
|
|
|
4,697.8 |
|
|
Total liabilities and stockholders equity |
|
$ |
8,705.7 |
|
|
$ |
7,807.4 |
|
|
See Notes to Consolidated Financial Statements
48
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, 2003 |
|
$ |
332.0 |
|
|
$ |
2,998.6 |
|
|
$ |
170.9 |
|
|
$ |
(151.1 |
) |
|
$ |
|
|
|
$ |
3,350.4 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
528.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications included in net income
due to sale of business |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.6 |
|
|
|
|
|
|
|
|
|
Translation adjustments, net of tax of $2.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30.8 |
|
|
|
|
|
|
|
|
|
Change in minimum pension liability, net
of tax of $(1.8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.0 |
|
|
|
|
|
|
|
|
|
Loss on derivative instruments, net of tax
of $0.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
569.9 |
|
Issuance of restricted stock, net of tax of $1.1 |
|
|
0.2 |
|
|
|
6.7 |
|
|
|
|
|
|
|
|
|
|
|
(5.6 |
) |
|
|
1.3 |
|
Amortization of unearned compensation, net
of tax of $(0.2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.5 |
|
|
|
0.5 |
|
Stock issued pursuant to employee stock plans,
net of tax of $12.5 |
|
|
4.4 |
|
|
|
122.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
126.9 |
|
Cash dividends ($0.46 per share) |
|
|
|
|
|
|
|
|
|
|
(153.6 |
) |
|
|
|
|
|
|
|
|
|
|
(153.6 |
) |
|
Balance, December 31, 2004 |
|
$ |
336.6 |
|
|
$ |
3,127.8 |
|
|
$ |
545.9 |
|
|
$ |
(109.8 |
) |
|
$ |
(5.1 |
) |
|
$ |
3,895.4 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
878.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments, net
of tax of $0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(65.0 |
) |
|
|
|
|
|
|
|
|
Change in minimum pension liability, net
of tax of $5.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12.2 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.0 |
) |
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
800.2 |
|
Issuance of restricted stock net of
cancellations, net of tax of $6.6 |
|
|
0.4 |
|
|
|
19.2 |
|
|
|
|
|
|
|
|
|
|
|
(12.3 |
) |
|
|
7.3 |
|
Amortization of unearned compensation, net of tax
of $(2.1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.0 |
|
|
|
5.0 |
|
Stock issued pursuant to employee stock plans,
net of tax of $19.8 |
|
|
6.2 |
|
|
|
243.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
249.5 |
|
Repurchase and retirement of common stock |
|
|
(1.7 |
) |
|
|
(96.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98.5 |
) |
Cash dividends ($0.475 per share) |
|
|
|
|
|
|
|
|
|
|
(161.1 |
) |
|
|
|
|
|
|
|
|
|
|
(161.1 |
) |
|
Balance, December 31, 2005 |
|
$ |
341.5 |
|
|
$ |
3,293.5 |
|
|
$ |
1,263.2 |
|
|
$ |
(188.0 |
) |
|
$ |
(12.4 |
) |
|
$ |
4,697.8 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
2,419.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications included in net income due
to sale of business |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.3 |
) |
|
|
|
|
|
|
|
|
Translation adjustments, net of tax of $4.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59.4 |
|
|
|
|
|
|
|
|
|
Change in minimum pension liability, net of tax
of $7.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17.8 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,459.4 |
|
Adoption of SFAS 158, net of tax of $21.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39.6 |
) |
|
|
|
|
|
|
(39.6 |
) |
Adoption of SFAS 123(R) |
|
|
|
|
|
|
(12.4 |
) |
|
|
|
|
|
|
|
|
|
|
12.4 |
|
|
|
|
|
Issuance of restricted stock, net of cancellations |
|
|
0.2 |
|
|
|
15.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15.3 |
|
Issuance of common stock pursuant to employee
stock plans |
|
|
2.4 |
|
|
|
97.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100.2 |
|
Tax benefit on stock plans |
|
|
|
|
|
|
17.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17.6 |
|
Stock-based compensation |
|
|
|
|
|
|
20.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20.7 |
|
Repurchase and retirement of common stock |
|
|
(24.2 |
) |
|
|
(1,831.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,855.9 |
) |
Cash dividends ($0.52 per share) |
|
|
|
|
|
|
|
|
|
|
(172.6 |
) |
|
|
|
|
|
|
|
|
|
|
(172.6 |
) |
|
Balance, December 31, 2006 |
|
$ |
319.9 |
|
|
$ |
1,600.6 |
|
|
$ |
3,509.6 |
|
|
$ |
(187.2 |
) |
|
$ |
|
|
|
$ |
5,242.9 |
|
|
See Notes to Consolidated Financial Statements
49
Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
2,398.6 |
|
|
$ |
874.4 |
|
|
$ |
525.3 |
|
Adjustments to reconcile income from continuing operations to net cash flows from
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
433.7 |
|
|
|
382.4 |
|
|
|
371.6 |
|
Amortization of net deferred gains on derivatives |
|
|
(5.1 |
) |
|
|
(5.7 |
) |
|
|
(7.9 |
) |
Stock-based compensation costs |
|
|
46.0 |
|
|
|
9.2 |
|
|
|
2.5 |
|
Acquired in-process research and development |
|
|
2.6 |
|
|
|
5.1 |
|
|
|
1.8 |
|
Provision for deferred income taxes |
|
|
77.7 |
|
|
|
7.4 |
|
|
|
48.4 |
|
Gain on sale of interest in affiliate |
|
|
(1,743.5 |
) |
|
|
|
|
|
|
|
|
Provision for income taxes on gain on sale of interest in affiliate |
|
|
708.3 |
|
|
|
|
|
|
|
|
|
Gain on disposal of assets |
|
|
(59.2 |
) |
|
|
(34.8 |
) |
|
|
(37.8 |
) |
Equity in income of affiliates |
|
|
(60.3 |
) |
|
|
(100.1 |
) |
|
|
(36.3 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(316.4 |
) |
|
|
(329.4 |
) |
|
|
(173.7 |
) |
Inventories |
|
|
(364.9 |
) |
|
|
(108.7 |
) |
|
|
(3.2 |
) |
Accounts payable |
|
|
69.1 |
|
|
|
122.3 |
|
|
|
48.3 |
|
Accrued employee compensation and other accrued liabilities |
|
|
104.1 |
|
|
|
92.4 |
|
|
|
127.3 |
|
Income taxes payable |
|
|
(98.0 |
) |
|
|
54.9 |
|
|
|
13.4 |
|
Income taxes paid on sale of interest in affiliate |
|
|
(555.1 |
) |
|
|
|
|
|
|
|
|
Liabilities for pensions and other postretirement benefits and other liabilities |
|
|
57.4 |
|
|
|
41.7 |
|
|
|
(30.4 |
) |
Other |
|
|
(105.3 |
) |
|
|
(61.5 |
) |
|
|
(67.5 |
) |
|
Net cash flows from continuing operations |
|
|
589.7 |
|
|
|
949.6 |
|
|
|
781.8 |
|
Net cash flows from discontinued operations |
|
|
0.4 |
|
|
|
5.8 |
|
|
|
1.9 |
|
|
Net cash flows from operating activities |
|
|
590.1 |
|
|
|
955.4 |
|
|
|
783.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures for capital assets |
|
|
(922.2 |
) |
|
|
(478.3 |
) |
|
|
(348.2 |
) |
Acquisition of businesses, net of cash acquired |
|
|
(66.2 |
) |
|
|
(46.8 |
) |
|
|
(6.6 |
) |
Purchase of short-term investments |
|
|
(3,882.9 |
) |
|
|
(77.0 |
) |
|
|
|
|
Proceeds from maturities of short-term investments |
|
|
3,606.2 |
|
|
|
|
|
|
|
|
|
Proceeds from disposal of assets |
|
|
135.4 |
|
|
|
90.1 |
|
|
|
106.9 |
|
Proceeds from sale of interest in affiliate |
|
|
2,400.0 |
|
|
|
|
|
|
|
|
|
Distributions from affiliates |
|
|
59.6 |
|
|
|
30.0 |
|
|
|
|
|
Receipt of true-up payment related to affiliate |
|
|
|
|
|
|
13.0 |
|
|
|
|
|
Proceeds from sale of business |
|
|
46.3 |
|
|
|
3.7 |
|
|
|
58.7 |
|
Additional investments in affiliates |
|
|
|
|
|
|
|
|
|
|
(7.1 |
) |
|
Net cash flows from continuing operations |
|
|
1,376.2 |
|
|
|
(465.3 |
) |
|
|
(196.3 |
) |
Net cash flows from discontinued operations |
|
|
|
|
|
|
(0.1 |
) |
|
|
(0.5 |
) |
|
Net cash flows from investing activities |
|
|
1,376.2 |
|
|
|
(465.4 |
) |
|
|
(196.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net (repayments) borrowings of commercial paper and other short-term debt |
|
|
(8.8 |
) |
|
|
(71.1 |
) |
|
|
35.5 |
|
Repayment of indebtedness |
|
|
|
|
|
|
|
|
|
|
(350.0 |
) |
Payment to terminate interest rate swap agreement |
|
|
|
|
|
|
(5.5 |
) |
|
|
|
|
Proceeds from issuance of common stock |
|
|
92.5 |
|
|
|
228.1 |
|
|
|
115.9 |
|
Repurchase of common stock |
|
|
(1,856.0 |
) |
|
|
(98.5 |
) |
|
|
|
|
Dividends |
|
|
(172.6 |
) |
|
|
(161.1 |
) |
|
|
(153.6 |
) |
Excess tax benefits from stock based compensation |
|
|
18.5 |
|
|
|
|
|
|
|
|
|
|
Net cash flows from financing activities |
|
|
(1,926.4 |
) |
|
|
(108.1 |
) |
|
|
(352.2 |
) |
|
Effect of foreign exchange rate changes on cash |
|
|
13.1 |
|
|
|
(3.9 |
) |
|
|
(14.1 |
) |
|
Increase in cash and cash equivalents |
|
|
53.0 |
|
|
|
378.0 |
|
|
|
220.6 |
|
Cash and cash equivalents, beginning of year |
|
|
697.0 |
|
|
|
319.0 |
|
|
|
98.4 |
|
|
Cash and cash equivalents, end of year |
|
$ |
750.0 |
|
|
$ |
697.0 |
|
|
$ |
319.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes paid |
|
$ |
1,197.5 |
|
|
$ |
299.7 |
|
|
$ |
143.2 |
|
Interest paid |
|
$ |
74.4 |
|
|
$ |
80.8 |
|
|
$ |
97.5 |
|
See Notes to Consolidated Financial Statements
50
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.
Baker Hughes is a major supplier of products and technology services and systems to the worldwide
oil and natural gas industry and provides products and services for drilling, formation evaluation,
completion and production of oil and natural gas wells.
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.
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.
Short-term Investments
We invest in auction rate securities, which are highly liquid, 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, creating short-term liquidity. The
securities trade at par and are callable at par on any interest payment date at the option of the
issuer. Interest is paid at the end of each auction period. We limit our investments in auction
rate securities to securities that carry a AAA (or equivalent) rating from a recognized rating
agency. The investments are classified as available-for-sale and are recorded at cost, which
approximates market value.
51
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
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 and Depreciation
Property 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 property. The
capitalized costs of computer software developed or purchased for internal use are included in
property.
Goodwill, Intangible Assets and Amortization
Goodwill, including goodwill associated with equity method investments, and intangible assets
with indefinite lives are not amortized. Intangible assets with finite useful lives are amortized
either on a straight-line basis over the assets estimated useful life or on a basis that reflects
the pattern in which the economic benefits of the intangible assets are realized.
Impairment of Long-Lived Assets
We review property, 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
52
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
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.
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.
Environmental Matters
Remediation costs are accrued based on estimates of known environmental remediation exposure
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. Such 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. Such 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 selling, general and administrative (SG&A) expense 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 SG&A expense in the consolidated statements of operations as
incurred. We recorded net foreign currency transaction and translation gains in SG&A in the
consolidated statement of operations of $1.7 million, $6.8 million and $4.0 million in 2006, 2005
and 2004, respectively.
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
the impact of certain of 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 cash flow or fair
value hedge 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.
53
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
New Accounting Standards
In February 2006, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 155, Accounting for Certain Hybrid Financial
Instruments an amendment of FASB Statements No. 133 and No. 140 (SFAS 155). SFAS 155 amends
SFAS 133, which required that a derivative embedded in a host contract that does not meet the
definition of a derivative be accounted for separately under certain conditions. SFAS 155 is
effective for all financial instruments acquired or issued (or subject to a remeasurement event)
following the start of an entitys first fiscal year beginning after September 15, 2006. We
adopted SFAS 155 on January 1, 2007, and there was no impact on our consolidated financial
statements.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting
for uncertainty in income taxes recognized in an entitys financial statements in accordance with
SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement
attribute for financial statement disclosure of tax positions taken or expected to be taken on a
tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted
FIN 48 on January 1, 2007. We currently estimate the cumulative effect of adopting FIN 48 to be a
reduction to consolidated retained earnings as of January 1, 2007 in the range of $45.0 million to
$60.0 million.
In September 2006, the FASB issued 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 is effective for financial statements issued for fiscal years beginning
after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS 157 on
January 1, 2008, and have not yet determined the impact, if any, on our consolidated financial
statements.
In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plansan 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 will be adopted on December 31, 2008, as allowed under SFAS 158.
See Note 14 for the incremental effect of applying SFAS 158 on our consolidated balance sheet as
of December 31, 2006.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin
108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current
Year Financial Statements (SAB 108). SAB 108 requires that public companies utilize a
dual-approach to assessing the quantitative effects of financial misstatements. This dual
approach includes both an income statement focused assessment and a balance sheet focused
assessment. SAB 108 is effective for fiscal years ending after November 15, 2006. We adopted SAB
108 on December 31, 2006, and there was no impact on our consolidated financial statements.
In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (FSP AUG AIR-1), which
addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use
of the accrue-in-advance method of accounting for planned major maintenance activities in annual
and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007 and we will
be applying the retrospective application for all financial statements presented. We currently do
not expect there to be a material impact on our consolidated financial statements as a result of
this adoption.
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 measure eligible 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 will adopt SFAS 159 on
January 1, 2008, and have not yet determined the impact, if any, on our consolidated financial
statements.
54
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 2. DISCONTINUED OPERATIONS
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 $42.5 million. We recorded a gain on the sale of $19.2 million, net of tax of $11.0
million, which consisted of an after-tax gain on the disposal of $16.9 million and $2.3 million
related to the recognition of the cumulative foreign currency translation adjustments into
earnings.
In September 2004, we completed the sale of Baker Hughes Mining Tools (BHMT), a product line
group within the Drilling and Evaluation segment that manufactured rotary drill bits used in the
mining industry, for $31.5 million. We recorded a gain on the sale of $0.2 million, net of tax of
$3.6 million, which consisted of an after-tax gain on the disposal of $6.8 million offset by a loss
of $6.6 million related to the recognition of the cumulative foreign currency translation
adjustments into earnings.
In January 2004, we completed the sale of BIRD Machine (BIRD) and recorded a loss on the
sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which were subject
to post-closing adjustments to the purchase price, and retained certain accounts receivable,
inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8
million to the buyer in settlement of the final purchase price adjustments. The adjustments were
the result of changes in the value of assets sold to and liabilities assumed by the buyer between
the date the initial sales price was negotiated and the closing of the sale.
We have reclassified the consolidated financial statements for all prior periods presented to
reflect these operations as discontinued. Summarized financial information from discontinued
operations is as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
SPD |
|
$ |
6.7 |
|
|
$ |
32.5 |
|
|
$ |
24.2 |
|
BHMT |
|
|
|
|
|
|
|
|
|
|
29.4 |
|
BIRD |
|
|
|
|
|
|
|
|
|
|
1.6 |
|
|
Total |
|
$ |
6.7 |
|
|
$ |
32.5 |
|
|
$ |
55.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
SPD |
|
$ |
1.8 |
|
|
$ |
7.7 |
|
|
$ |
4.7 |
|
BHMT |
|
|
|
|
|
|
|
|
|
|
1.1 |
|
BIRD |
|
|
|
|
|
|
|
|
|
|
(0.2 |
) |
|
Total |
|
|
1.8 |
|
|
|
7.7 |
|
|
|
5.6 |
|
|
Income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
SPD |
|
|
(0.6 |
) |
|
|
(2.8 |
) |
|
|
(1.8 |
) |
BHMT |
|
|
|
|
|
|
|
|
|
|
(0.3 |
) |
BIRD |
|
|
|
|
|
|
|
|
|
|
0.1 |
|
|
Total |
|
|
(0.6 |
) |
|
|
(2.8 |
) |
|
|
(2.0 |
) |
|
Income (loss) before gain (loss) on disposal: |
|
|
|
|
|
|
|
|
|
|
|
|
SPD |
|
|
1.2 |
|
|
|
4.9 |
|
|
|
2.9 |
|
BHMT |
|
|
|
|
|
|
|
|
|
|
0.8 |
|
BIRD |
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
Total |
|
|
1.2 |
|
|
|
4.9 |
|
|
|
3.6 |
|
|
Gain (loss) on disposal, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
SPD |
|
|
19.2 |
|
|
|
|
|
|
|
|
|
BHMT |
|
|
|
|
|
|
|
|
|
|
0.2 |
|
BIRD |
|
|
|
|
|
|
|
|
|
|
(0.5 |
) |
|
Total |
|
|
19.2 |
|
|
|
|
|
|
|
(0.3 |
) |
|
Income (loss) from discontinued operations |
|
$ |
20.4 |
|
|
$ |
4.9 |
|
|
$ |
3.3 |
|
|
55
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Assets and liabilities of discontinued operations are as follows for the years ended December
31:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Accounts receivable, net |
|
$ |
|
|
|
$ |
6.0 |
|
Inventories |
|
|
|
|
|
|
8.8 |
|
Property, net |
|
|
|
|
|
|
1.8 |
|
|
Assets of discontinued operations |
|
$ |
|
|
|
$ |
16.6 |
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
2.7 |
|
Accrued employee compensation |
|
|
|
|
|
|
0.7 |
|
Other accrued liabilities |
|
|
|
|
|
|
0.4 |
|
|
Liabilities of discontinued operations |
|
$ |
|
|
|
$ |
3.8 |
|
|
NOTE 3. ACQUISITIONS
In January 2006, we acquired Nova Technology Corporation (Nova) for $55.4 million, net of
cash acquired of $3.0 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 $29.7 million of goodwill, $24.3 million
of intangible assets and assigned $2.6 million to in-process research and development. Under the
terms of the purchase agreement, the former owners of Nova are entitled to additional purchase
price consideration of up to $3.0 million based on certain post-closing events to the extent that
those events occur no later than January 31, 2016.
In December 2005, we purchased Zeroth Technology Limited (Zertech), a developer of an
expandable metal sealing element, for $20.3 million in cash. As a result of the acquisition, we
recorded $9.4 million of goodwill and $10.3 million of intangible assets. Under the terms of the
purchase agreement, the former owners of Zertech are entitled to additional purchase price
consideration of up to approximately $14.0 million based on the performance of the business during
2006, 2007 and 2008.
We owned a 50% interest in the QuantX Wellbore Instrumentation venture (QuantX) and in
October 2005, we purchased the remaining 50% interest in QuantX for $27.2 million, subject to final
purchase price adjustments. We recorded $28.4 million of goodwill, $19.6 million of intangibles
and assigned $5.1 million to in-process research and development.
In 2002, we entered into a venture, Luna Energy, L.L.C. (Luna), in which we had a 40%
interest. In December 2004, we acquired the remaining 60% interest in Luna for $1.0 million in
cash. As a result of the acquisition, we recorded $19.0 million of goodwill, $5.5 million of
intangible assets and assigned $1.8 million to in-process research and development.
All acquisitions above are included in the Completion and Production segment. 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.
NOTE 4. STOCK-BASED COMPENSATION
On January 1, 2006, we adopted SFAS 123(R), which establishes accounting for equity
instruments exchanged for employee services. SFAS 123(R) is a revision of SFAS 123 and supersedes
APB 25. Under the provisions of SFAS 123(R), 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.
Prior to January 1, 2006, we accounted for stock-based compensation to employees under the
intrinsic value method in accordance with APB 25, as permitted under SFAS 123. Under this method,
compensation cost was recognized for the difference between the quoted market price on the date of
grant, less the amount, if any, the employee was required to pay for the common stock.
Accordingly, we did not recognize compensation cost for our stock option awards or our
employee stock purchase plan because we issue options at exercise prices equal to the market value
of our stock on the date of grant and because our employee stock purchase plan was noncompensatory.
We did record compensation cost for our restricted stock awards and restricted stock units.
56
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
SFAS 123(R) also clarified the accounting in SFAS 123 related to estimating the service period
for employees that are or become retirement eligible during the vesting period, requiring that the
recognition of compensation expense for these employees be accelerated. This impacts the timing of
expense recognition, but not the total expense to be recognized over the vesting period. In the
first quarter of 2005, we adopted this new methodology on a prospective basis. The cumulative
effect of this clarification was $11.8 million, net of tax, and related only to stock option
awards. We have included this amount in our pro forma disclosure for stock-based compensation
costs for the year ended December 31, 2005.
We adopted SFAS 123(R) using the modified prospective application method and, accordingly, no
prior periods have been restated. Under this method, compensation cost recognized during the year
ended December 31, 2006 includes: (a) compensation cost for all stock-based awards granted prior
to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in
accordance with the original provisions of SFAS 123, and (b) compensation cost for all stock-based
awards granted after January 1, 2006, based on the grant-date fair value estimated in accordance
with SFAS 123(R). 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. SFAS 123(R) requires forfeitures to be estimated at the time of grant and
revised, if necessary, in subsequent periods to reflect actual forfeitures. As a result of the
adoption of SFAS 123(R), the balance in unearned compensation recorded in stockholders equity as
of January 1, 2006, of $12.4 million, net of tax, was reclassified to and reduced the balance of
capital in excess of par value.
The FASB Staff Position No. FAS 123 (R)-3, Transition Election Related to Accounting for Tax
Effects of Share-Based Payment Awards (FSP 123(R)-3), provides an alternative method of
calculating excess tax benefits (the APIC pool) from the
method defined in SFAS 123(R). A
one-time election to adopt the transition method in FSP 123(R)-3 is available to those entities
adopting SFAS 123(R). The Company has calculated the APIC pool using the alternative method
outlined in FSP 123(R)-3.
The following table summarizes stock-based compensation costs recognized under SFAS 123(R) for
the year ended December 31, 2006 and under APB 25 for the years ended December 31, 2005 and 2004.
There were no stock-based compensation costs capitalized as the amounts were not material.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Stock-based compensation costs |
|
$ |
46.0 |
|
|
$ |
9.2 |
|
|
$ |
2.5 |
|
Tax benefit |
|
|
(10.1 |
) |
|
|
(3.1 |
) |
|
|
(0.9 |
) |
|
Stock-based compensation costs, net of tax |
|
$ |
35.9 |
|
|
$ |
6.1 |
|
|
$ |
1.6 |
|
|
The application of SFAS 123(R) had the following effect on the as reported amounts for the
year ended December 31, 2006 compared to amounts that would have been reported using the intrinsic
value method pursuant to our previous accounting method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intrinsic |
|
|
|
|
|
|
|
|
|
|
Value |
|
|
|
|
|
|
SFAS 123(R) |
|
Method |
|
|
As Reported |
|
Effect |
|
(APB 25) |
|
Income from continuing operations before income taxes |
|
$ |
3,736.8 |
|
|
$ |
26.4 |
|
|
$ |
3,763.2 |
|
Income from continuing operations |
|
|
2,398.6 |
|
|
|
21.5 |
|
|
|
2,420.1 |
|
Net income |
|
|
2,419.0 |
|
|
|
21.5 |
|
|
|
2,440.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
7.26 |
|
|
$ |
0.07 |
|
|
$ |
7.33 |
|
Net income |
|
|
7.32 |
|
|
|
0.07 |
|
|
|
7.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
7.21 |
|
|
$ |
0.06 |
|
|
$ |
7.27 |
|
Net income |
|
|
7.27 |
|
|
|
0.06 |
|
|
|
7.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities |
|
$ |
590.1 |
|
|
$ |
18.5 |
|
|
$ |
608.6 |
|
Cash flows from financing activities |
|
|
(1,926.4 |
) |
|
|
(18.5 |
) |
|
|
(1,944.9 |
) |
57
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
The following table illustrates the pro forma effect on net income and earnings per share
for the years ended December 31, 2005 and 2004 if we had recognized compensation expense by
applying the fair value based method to all awards as provided for under SFAS 123:
|
|
|
|
|
|
|
|
|
|
|
Pro Forma |
|
Pro Forma |
|
|
2005 |
|
2004 |
|
Net income, as reported |
|
$ |
878.4 |
|
|
$ |
528.6 |
|
Add: Stock-based
compensation for restricted
stock awards and units
included in reported net
income, net of tax |
|
|
6.1 |
|
|
|
1.6 |
|
Deduct: Stock-based
compensation determined under
SFAS 123, net of tax |
|
|
(35.0 |
) |
|
|
(23.1 |
) |
|
Pro forma net income |
|
$ |
849.5 |
|
|
$ |
507.1 |
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
2.59 |
|
|
$ |
1.58 |
|
Pro forma |
|
|
2.50 |
|
|
|
1.52 |
|
Diluted EPS: |
|
|
|
|
|
|
|
|
As reported |
|
$ |
2.57 |
|
|
$ |
1.58 |
|
Pro forma |
|
|
2.49 |
|
|
|
1.51 |
|
For our stock options and restricted stock awards and units, we currently have 32.5 million
shares authorized for issuance and as of December 31, 2006, approximately 10.2 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, we reduced the service period 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. For the years 2005 and 2004, the
expected life was based on historical trends. For the year ended December 31, 2006, the expected
life is based on our historical exercise trends and post-vest termination data incorporated into a
forward looking stock price model. For the years 2005 and 2004, our expected volatility is based
on the historical volatility of our stock for a period approximating the expected life. For the
year ended December 31, 2006, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
Actual |
|
Pro Forma |
|
Pro Forma |
|
Expected life (years) |
|
|
5.0 |
|
|
|
3.7 |
|
|
|
3.5 |
|
Risk-free interest rate |
|
|
4.8 |
% |
|
|
3.7 |
% |
|
|
2.8 |
% |
Volatility |
|
|
31.1 |
% |
|
|
35.0 |
% |
|
|
39.9 |
% |
Dividend yield |
|
|
0.7 |
% |
|
|
1.0 |
% |
|
|
1.3 |
% |
Weighted average fair value per share at grant date |
|
$ |
26.15 |
|
|
$ |
14.62 |
|
|
$ |
11.16 |
|
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, 2005 |
|
|
5,575 |
|
|
$ |
38.84 |
|
Granted |
|
|
678 |
|
|
|
77.84 |
|
Exercised |
|
|
(1,841 |
) |
|
|
35.28 |
|
Forfeited |
|
|
(107 |
) |
|
|
46.11 |
|
Expired |
|
|
(9 |
) |
|
|
44.73 |
|
|
Outstanding at December 31, 2006 |
|
|
4,296 |
|
|
$ |
46.35 |
|
|
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
2006, 2005 and 2004 was $73.6 million, $84.6 million and $53.6 million, respectively. The income
tax benefit realized from stock options exercised was $16.9 million for the year ended December 31,
2006. The total fair value of options vested in 2006, 2005 and 2004 was $20.2 million, $20.4
million and $31.5 million, respectively. As of December 31, 2006, there was $12.1 million of total
unrecognized compensation cost related to nonvested stock options which is expected to be
recognized over a weighted average period of 1.9 years.
The following table summarizes information about stock options outstanding as of December 31,
2006 (in thousands, except per option prices and remaining life):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
Exercisable |
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
Remaining |
|
Weighted Average |
|
|
|
|
|
Remaining |
|
Weighted Average |
|
|
Number of |
|
Contractual Life |
|
Exercise Price Per |
|
Number of |
|
Contractual Life |
|
Exercise Price Per |
Range of Exercise Prices |
|
Options |
|
(In years) |
|
Option |
|
Options |
|
(In years) |
|
Option |
|
$14.49 $21.00 |
|
|
96 |
|
|
|
2.0 |
|
|
$ |
20.52 |
|
|
|
96 |
|
|
|
2.0 |
|
|
$ |
20.52 |
|
22.88 33.50 |
|
|
784 |
|
|
|
5.6 |
|
|
|
30.14 |
|
|
|
784 |
|
|
|
5.6 |
|
|
|
30.14 |
|
35.81 47.82 |
|
|
2,129 |
|
|
|
6.3 |
|
|
|
40.71 |
|
|
|
1,163 |
|
|
|
5.3 |
|
|
|
41.59 |
|
56.21 80.73 |
|
|
1,287 |
|
|
|
8.9 |
|
|
|
67.49 |
|
|
|
197 |
|
|
|
8.6 |
|
|
|
56.42 |
|
|
Total |
|
|
4,296 |
|
|
|
6.9 |
|
|
$ |
46.35 |
|
|
|
2,240 |
|
|
|
5.6 |
|
|
$ |
37.99 |
|
|
The aggregate intrinsic value of stock options outstanding at December 31, 2006 was $121.6
million, of which $82.2 million relates to awards vested and exercisable and $39.5 million relates
to awards expected to vest. The intrinsic value for stock options outstanding is calculated as the
amount by which the quoted price of $74.66 of our common stock at December 31, 2006 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, 2005 |
|
|
669 |
|
|
$ |
42.22 |
|
|
|
77 |
|
|
$ |
42.60 |
|
Granted |
|
|
327 |
|
|
|
73.97 |
|
|
|
79 |
|
|
|
74.00 |
|
Vested |
|
|
(233 |
) |
|
|
40.53 |
|
|
|
(27 |
) |
|
|
43.30 |
|
Forfeited |
|
|
(16 |
) |
|
|
62.02 |
|
|
|
(5 |
) |
|
|
53.62 |
|
|
Nonvested balance at December 31, 2006 |
|
|
747 |
|
|
$ |
56.23 |
|
|
|
124 |
|
|
$ |
61.91 |
|
|
The weighted average grant date fair value per share for RSAs in 2005 and 2004 was $44.28 and
$42.22, respectively. The weighted average grant date fair value per share for RSUs in 2005 was
$42.60. There were no RSUs granted in 2004.
The total grant date fair value of RSAs and RSUs vested in 2006 and 2004 was $10.6 million and
$2.3 million, respectively. There were no RSAs or RSUs that vested in 2005. As of December 31,
2006, there was $25.9 million and $4.8 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 2.1 years.
Employee Stock Purchase Plan
Our Employee Stock Purchase Plan (ESPP) allows eligible employees to purchase shares of our
stock at 85% of market value on the first or last business day, whichever is lower, of the calendar
year. Purchases are limited to 10% of an employees base salary. We currently have 14.5 million
shares authorized for issuance under the ESPP and at December 31, 2006, there were 2.9 million
shares reserved for future issuance under the ESPP. Compensation expense determined under SFAS
123(R) for the year ended December 31, 2006 was calculated using the Black-Scholes option pricing
model with the following assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
Actual |
|
Pro Forma |
|
Pro Forma |
|
Expected life (years) |
|
|
1.0 |
|
|
|
1.0 |
|
|
|
1.0 |
|
Interest rate |
|
|
4.4 |
% |
|
|
2.7 |
% |
|
|
1.3 |
% |
Volatility |
|
|
28.0 |
% |
|
|
26.6 |
% |
|
|
27.8 |
% |
Dividend yield |
|
|
0.9 |
% |
|
|
1.1 |
% |
|
|
1.4 |
% |
Weighted average fair value per share at grant date |
|
$ |
7.66 |
|
|
$ |
10.05 |
|
|
$ |
7.53 |
|
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.
NOTE 5. SALE OF INTEREST AND INVESTMENTS IN AFFILIATES
We have investments in affiliates that are accounted for using the equity method of
accounting. 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 $1,743.5 million ($1,035.2 million, net of tax).
Prior to our sale, during 2006 and 2005, we received distributions of $59.6 million and $30.0
million, respectively, from WesternGeco, which were recorded as reductions in the carrying value of
our investment.
During 2005, we received $13.3 million from Schlumberger related to a true-up payment
associated with revenues earned by WesternGeco during the four year period ending November 2004
from each partys contributed multiclient seismic data libraries. We recorded $13.0 million as a
reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest
income. The income tax effect of $3.3 million related to this payment is included in our provision for
income taxes for the year ended December 31, 2005.
60
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
In November 2000, we entered into an agreement with WesternGeco, whereby WesternGeco
subleases a facility from us for a period of ten years at then current market rates. In 2006, we
entered into an extension of the sublease for five additional years with rent to be determined
based on market rates in 2010. During 2006, 2005 and 2004, we received payments of $5.6 million,
$6.5 million and $5.5 million, respectively, from WesternGeco related to this lease.
In February 2004, we completed the sale of our minority interest in Petreco International, a
venture we entered into in 2001, for $35.8 million, of which $7.4 million was placed in escrow
pending the outcome of potential indemnification obligations pursuant to the sales agreement. The
escrow has now been received in full.
The following table includes summarized unaudited combined financial information for the
affiliates in which we account for our interests using the equity method of accounting. Included
in the table are the operating and financial position results for WesternGeco as of March 31, 2006,
the most recent date for which information is available. All other information for affiliates is
as of December 31.
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Combined operating results: |
|
|
|
|
|
|
|
|
Revenues |
|
$ |
582.9 |
|
|
$ |
1,700.7 |
|
Operating income |
|
|
166.1 |
|
|
|
327.3 |
|
Net income |
|
|
145.2 |
|
|
|
279.7 |
|
|
|
|
|
|
|
|
|
|
Combined financial position: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
1,229.4 |
|
|
$ |
1,110.8 |
|
Noncurrent assets |
|
|
1,116.1 |
|
|
|
1,056.6 |
|
|
Total assets |
|
$ |
2,345.5 |
|
|
$ |
2,167.4 |
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
546.0 |
|
|
$ |
522.7 |
|
Noncurrent liabilities |
|
|
89.1 |
|
|
|
85.2 |
|
Stockholders equity |
|
|
1,710.4 |
|
|
|
1,559.5 |
|
|
Total liabilities and stockholders equity |
|
$ |
2,345.5 |
|
|
$ |
2,167.4 |
|
|
As of December 31, 2006 and 2005, the excess of our investments as recorded on our balance
sheet over our pro-rata share of the shareholders equity as reported by the affiliates was $8.4
million and $239.4 million, respectively.
NOTE 6. INCOME TAXES
The provision for income taxes on income from continuing operations is comprised of the
following for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
861.5 |
|
|
$ |
146.3 |
|
|
$ |
51.7 |
|
Foreign |
|
|
371.1 |
|
|
|
251.1 |
|
|
|
150.5 |
|
|
Total current |
|
|
1,232.6 |
|
|
|
397.4 |
|
|
|
202.2 |
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
97.9 |
|
|
|
7.0 |
|
|
|
45.4 |
|
Foreign |
|
|
7.7 |
|
|
|
0.4 |
|
|
|
3.0 |
|
|
Total deferred |
|
|
105.6 |
|
|
|
7.4 |
|
|
|
48.4 |
|
|
Provision for income taxes |
|
$ |
1,338.2 |
|
|
$ |
404.8 |
|
|
$ |
250.6 |
|
|
61
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
The geographic sources of income from continuing operations before income taxes are as
follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
United States |
|
$ |
1,917.3 |
|
|
$ |
409.6 |
|
|
$ |
213.9 |
|
Foreign |
|
|
1,819.5 |
|
|
|
869.6 |
|
|
|
562.0 |
|
|
Income from
continuing
operations before
income taxes |
|
$ |
3,736.8 |
|
|
$ |
1,279.2 |
|
|
$ |
775.9 |
|
|
Tax benefits of $19.4 million, $19.8 million and $12.5 million associated with the exercise of
employee stock options were allocated to equity and recorded in capital in excess of par value in
the years ended December 31, 2006, 2005 and 2004, respectively.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Statutory income tax at 35% |
|
$ |
1,307.9 |
|
|
$ |
447.7 |
|
|
$ |
271.6 |
|
Effect of sale of interest in affiliate |
|
|
98.1 |
|
|
|
|
|
|
|
|
|
Effect of foreign operations |
|
|
(86.9 |
) |
|
|
(46.0 |
) |
|
|
(28.3 |
) |
Net tax (benefit) charge related to foreign losses |
|
|
(2.7 |
) |
|
|
5.5 |
|
|
|
4.0 |
|
State income taxes net of U.S. tax benefit |
|
|
12.1 |
|
|
|
8.8 |
|
|
|
3.4 |
|
Cumulative tax effect of SRP |
|
|
|
|
|
|
(10.6 |
) |
|
|
|
|
Other net |
|
|
9.7 |
|
|
|
(0.6 |
) |
|
|
(0.1 |
) |
|
Provision for income taxes |
|
$ |
1,338.2 |
|
|
$ |
404.8 |
|
|
$ |
250.6 |
|
|
During 2006, we provided $708.3 million for taxes related to the sale of our interest in
WesternGeco. Approximately $98.1 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.
In 2005, we recognized a $10.6 million deferred tax asset attributable to the cumulative
temporary difference between the carrying values of our Supplemental Retirement Plan (SRP) for
financial reporting and income tax purposes, which had the effect of reducing tax expense.
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.
While we have provided for the taxes that we believe will ultimately be payable as a result of
these assessments, the aggregate assessments are approximately $36.2 million in excess of the taxes
provided for in our consolidated financial statements.
In addition to the aforementioned assessments that have been received from various tax
authorities, we provide for taxes in certain situations where assessments have not been received.
In those situations, we consider it probable that the taxes ultimately payable will exceed the
amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under
the guidance in SFAS No. 5, Accounting for Contingencies, and are included in both income taxes in
current liabilities and in deferred income taxes and other tax liabilities in the consolidated
balance sheets. At December 31, 2006 and 2005, deferred income taxes and other tax liabilities, as
reflected in the consolidated balance sheets, are $300.2 million and $228.1 million, respectively,
which include $108.3 million and $30.6 million of deferred tax liabilities and $191.9 million and
$197.5 million of other long-term tax liabilities.
In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income
taxes recognized in an entitys financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes. It prescribes a recognition threshold and measurement attribute for financial
statement disclosure of tax positions taken or expected to be taken on a tax return. FIN 48 is
effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 on January 1,
2007. We currently estimate the cumulative effect of adopting FIN 48 to be a reduction to
consolidated retained earnings as of January 1, 2007 in the range of $45.0 million to $60.0
million.
62
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:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Receivables |
|
$ |
9.9 |
|
|
$ |
9.9 |
|
Inventory |
|
|
138.3 |
|
|
|
125.9 |
|
Property |
|
|
53.3 |
|
|
|
40.8 |
|
Employee benefits |
|
|
63.4 |
|
|
|
28.7 |
|
Other accrued expenses |
|
|
46.9 |
|
|
|
31.5 |
|
Operating loss carryforwards |
|
|
41.1 |
|
|
|
44.1 |
|
Tax credit carryforwards |
|
|
20.7 |
|
|
|
46.7 |
|
Capitalized research and development costs |
|
|
39.2 |
|
|
|
63.5 |
|
Other |
|
|
29.6 |
|
|
|
46.0 |
|
|
Subtotal |
|
|
442.4 |
|
|
|
437.1 |
|
Valuation allowances |
|
|
(50.7 |
) |
|
|
(42.4 |
) |
|
Total |
|
|
391.7 |
|
|
|
394.7 |
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Goodwill |
|
|
130.8 |
|
|
|
113.4 |
|
Undistributed earnings of foreign subsidiaries |
|
|
150.3 |
|
|
|
61.7 |
|
Other |
|
|
30.4 |
|
|
|
20.7 |
|
|
Total |
|
|
311.5 |
|
|
|
195.8 |
|
|
Net deferred tax asset |
|
$ |
80.2 |
|
|
$ |
198.9 |
|
|
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 carryforwards in certain non-U.S. jurisdictions where our operations have decreased,
currently ceased or we have withdrawn entirely.
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 already provided to be indefinitely reinvested, as we have no
intention to repatriate these earnings. These additional foreign earnings could become subject to
additional tax if remitted, or deemed remitted, as a dividend; however, it is not practicable to
estimate the additional amount of taxes payable.
At December 31, 2006, we had approximately $14.0 million of foreign tax credits which may be
carried forward indefinitely under applicable foreign law and $6.7 million of state tax credits
expiring in varying amounts between 2016 and 2021. The operating loss carryforwards without a
valuation allowance will expire in varying amounts over the next twenty years.
NOTE 7. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Weighted average common shares outstanding for basic EPS |
|
|
330.6 |
|
|
|
339.4 |
|
|
|
333.8 |
|
Effect of dilutive securities stock plans |
|
|
2.0 |
|
|
|
2.1 |
|
|
|
1.8 |
|
|
Adjusted weighted average common shares outstanding for diluted EPS |
|
|
332.6 |
|
|
|
341.5 |
|
|
|
335.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future potentially dilutive shares excluded from diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Options with an exercise price greater than the average market
price for the period |
|
|
0.7 |
|
|
|
0.7 |
|
|
|
4.6 |
|
63
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
NOTE 8. INVENTORIES
Inventories are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Finished goods |
|
$ |
1,239.5 |
|
|
$ |
914.5 |
|
Work in process |
|
|
188.0 |
|
|
|
134.2 |
|
Raw materials |
|
|
101.3 |
|
|
|
77.6 |
|
|
Total |
|
$ |
1,528.8 |
|
|
$ |
1,126.3 |
|
|
NOTE 9. PROPERTY
Property is comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
Period |
|
2006 |
|
2005 |
|
Land |
|
|
|
|
|
$ |
46.1 |
|
|
$ |
39.7 |
|
Buildings and improvements |
|
5 - 40 years |
|
|
661.0 |
|
|
|
611.7 |
|
Machinery and equipment |
|
2 - 20 years |
|
|
2,387.6 |
|
|
|
2,022.3 |
|
Rental tools and equipment |
|
1 - 8 years |
|
|
1,419.2 |
|
|
|
1,157.5 |
|
|
Total property |
|
|
|
|
|
|
4,513.9 |
|
|
|
3,831.2 |
|
Accumulated depreciation |
|
|
|
|
|
|
(2,713.4 |
) |
|
|
(2,475.7 |
) |
|
Property net |
|
|
|
|
|
$ |
1,800.5 |
|
|
$ |
1,355.5 |
|
|
NOTE 10. 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, 2004 |
|
$ |
902.9 |
|
|
$ |
364.1 |
|
|
$ |
1,267.0 |
|
Goodwill from acquisitions during the period |
|
|
|
|
|
|
48.1 |
|
|
|
48.1 |
|
Translation adjustments and other |
|
|
1.2 |
|
|
|
(0.5 |
) |
|
|
0.7 |
|
|
Balance as of December 31, 2005 |
|
|
904.1 |
|
|
|
411.7 |
|
|
|
1,315.8 |
|
Goodwill from acquisitions during the period |
|
|
5.3 |
|
|
|
30.4 |
|
|
|
35.7 |
|
Adjustments for final purchase price
allocations of previous acquisitions |
|
|
|
|
|
|
(5.0 |
) |
|
|
(5.0 |
) |
Translation adjustments and other |
|
|
(0.2 |
) |
|
|
0.7 |
|
|
|
0.5 |
|
|
Balance as of December 31, 2006 |
|
$ |
909.2 |
|
|
$ |
437.8 |
|
|
$ |
1,347.0 |
|
|
64
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
We perform an annual impairment test of goodwill as of October 1 of every year. There
were no impairments of goodwill in 2006, 2005 or 2004 related to the annual impairment test.
Intangible assets are comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
|
Gross |
|
|
|
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
Carrying |
|
Accumulated |
|
|
|
|
|
Carrying |
|
Accumulated |
|
|
|
|
Amount |
|
Amortization |
|
Net |
|
Amount |
|
Amortization |
|
Net |
|
Technology based |
|
$ |
236.7 |
|
|
$ |
(87.2 |
) |
|
$ |
149.5 |
|
|
$ |
204.8 |
|
|
$ |
(71.3 |
) |
|
$ |
133.5 |
|
Contract based |
|
|
13.8 |
|
|
|
(6.6 |
) |
|
|
7.2 |
|
|
|
11.1 |
|
|
|
(6.5 |
) |
|
|
4.6 |
|
Marketing related |
|
|
5.7 |
|
|
|
(5.7 |
) |
|
|
|
|
|
|
6.1 |
|
|
|
(5.6 |
) |
|
|
0.5 |
|
Customer based |
|
|
13.7 |
|
|
|
(2.4 |
) |
|
|
11.3 |
|
|
|
6.4 |
|
|
|
(0.4 |
) |
|
|
6.0 |
|
Other |
|
|
0.7 |
|
|
|
(0.4 |
) |
|
|
0.3 |
|
|
|
1.2 |
|
|
|
(0.7 |
) |
|
|
0.5 |
|
|
Total amortizable intangible assets |
|
|
270.6 |
|
|
|
(102.3 |
) |
|
|
168.3 |
|
|
|
229.6 |
|
|
|
(84.5 |
) |
|
|
145.1 |
|
Marketing related intangible asset
with an indefinite useful life |
|
|
22.1 |
|
|
|
|
|
|
|
22.1 |
|
|
|
18.3 |
|
|
|
|
|
|
|
18.3 |
|
|
Total |
|
$ |
292.7 |
|
|
$ |
(102.3 |
) |
|
$ |
190.4 |
|
|
$ |
247.9 |
|
|
$ |
(84.5 |
) |
|
$ |
163.4 |
|
|
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, 2006, 2005 and
2004 was $20.0 million, $15.2 million and $14.9 million, respectively. Estimated amortization
expense for each of the subsequent five fiscal years is expected to be within the range of $13.4
million to $20.4 million.
NOTE 11. INDEBTEDNESS
Total debt consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
6.25% Notes due January 2009 with an
effective interest rate of 4.69%, net of
unamortized discount and debt issuance
costs of $0.7 at December 31, 2006 ($1.0 at
December 31, 2005) |
|
$ |
334.8 |
|
|
$ |
339.5 |
|
|
|
|
|
|
|
|
|
|
6.00% Notes due February 2009 with an
effective interest rate of 6.11%, net of
unamortized discount and debt issuance
costs of $0.4 at December 31, 2006 ($0.5 at
December 31, 2005) |
|
|
199.6 |
|
|
|
199.5 |
|
|
|
|
|
|
|
|
|
|
8.55% Debentures due June 2024 with an
effective interest rate of 8.76%, net of
unamortized discount and debt issuance
costs of $2.4 at December 31, 2006 ($2.5 at
December 31, 2005) |
|
|
147.6 |
|
|
|
147.5 |
|
|
|
|
|
|
|
|
|
|
6.875% Notes due January 2029 with an
effective interest rate of 7.08%, net of
unamortized discount and debt issuance
costs of $8.3 at December 31, 2006 ($8.5 at
December 31, 2005) |
|
|
391.7 |
|
|
|
391.5 |
|
|
|
|
|
|
|
|
|
|
Other debt |
|
|
1.4 |
|
|
|
9.9 |
|
|
Total debt |
|
|
1,075.1 |
|
|
|
1,087.9 |
|
Less short-term debt and current maturities |
|
|
1.3 |
|
|
|
9.9 |
|
|
Long-term debt |
|
$ |
1,073.8 |
|
|
$ |
1,078.0 |
|
|
At December 31, 2006, we had $1,057.8 million of credit facilities with commercial banks, of
which $500.0 million is a committed revolving credit facility (the facility) that expires in July
2011. The facility provides for up to two one-year extensions, subject to the approval and
acceptance by the lenders, among other conditions. In addition, the facility contains a provision
to allow for an
65
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
increase in the facility amount of an additional $500.0 million, subject to the approval and
acceptance by the lenders, among other conditions. The facility contains certain covenants which,
among other things, require the maintenance of a funded indebtedness to total capitalization ratio
(a defined formula per the facility) of less than or equal to 0.60, 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 facility may be accelerated. Such events of default include
payment defaults to lenders under the facility, covenant defaults and other customary defaults. At
December 31, 2006, we were in compliance with all of the facility covenants. There were no direct
borrowings under the facility during the year ended December 31, 2006; however, to the extent we
have outstanding commercial paper, our ability to borrow under the facility is reduced. At
December 31, 2006, we had no outstanding commercial paper.
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 $10.5 million and $15.5 million are included in the 6.25% Notes
due January 2009 and reported in long-term debt in the consolidated balance sheets at December 31,
2006 and 2005, respectively.
Maturities of debt at December 31, 2006 are as follows: 2007 $1.3 million; 2008 $0.0
million; 2009 $534.5 million; 2010 $0.0 million, 2011 $0.0 million; and $539.3 million
thereafter.
NOTE 12. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Our financial instruments include cash and short-term investments, receivables, payables, debt
and foreign currency forward contracts. Except as described below, the estimated fair value of
such financial instruments at December 31, 2006 and 2005 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, 2006 and 2005 was $1,171.0 million and
$1,233.6 million, respectively, which differs from the carrying amounts of $1,075.1 million and
$1,087.9 million, respectively, included in our consolidated balance sheets.
Foreign Currency Forward Contracts
At December 31, 2006, we had entered into several foreign currency forward contracts with
notional amounts aggregating $105.0 million to hedge exposure to currency fluctuations in various
foreign currency payables and receivables, including British Pound Sterling, Norwegian Krone, Euro,
Indonesian Rupiah and Brazilian Real. These contracts are designated and qualify as fair value
hedging instruments. Based on quoted market prices as of December 31, 2006 for contracts with
similar terms and maturity dates, we recorded a loss of $0.2 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 selling, general
and administrative expense in the consolidated statement of operations.
At December 31, 2005, we had entered into several foreign currency forward contracts with
notional amounts aggregating $65.0 million to hedge exposure to currency fluctuations in various
foreign currency payables and receivables, including British Pound Sterling, Norwegian Krone, Euro
and Brazilian Real. These contracts were designated and qualified as fair value hedging
instruments. Based on quoted market prices as of December 31, 2005 for contracts with similar
terms and maturity dates, we recorded a gain of $0.1 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 selling, general and
administrative expense in the 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 unlikely 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.
66
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 we
are exposed to minimal risk 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 major banks that may exceed federally insured limits. We
periodically assess the financial condition of the institutions and believe that the risk of any
loss is minimal.
NOTE 13. SEGMENT AND RELATED INFORMATION
We are a provider of drilling, formation evaluation, completion and production products and
services to the worldwide oil and natural gas industry. We have historically reported our results
under three segments Drilling and Evaluation, Completion and Production and WesternGeco. The
WesternGeco segment consisted of our 30% interest in WesternGeco which we sold in April 2006.
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 include 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. The Drilling and Evaluation
segment provides products and services used to drill and evaluate oil and natural gas
wells. |
|
|
|
|
The Completion and Production segment consists of the Baker Oil Tools (workover, fishing
and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift
(electrical submersible pumps and progressing cavity pumps) divisions and the
ProductionQuest business unit. 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 accounting changes. The Corporate and Other column includes corporate-related items,
the pre-tax gain on the sale of our interest in WesternGeco of $1,743.5 million, the financial
charge of $46.1 million recorded in connection with the settlement negotiations with the SEC and
DOJ, results of insignificant operations and, as it relates to segment profit (loss), income and
expense not allocated to the segments. The Corporate and Other column also includes assets of
discontinued operations as of December 31, 2005 and 2004. Summarized financial information is
shown in the following table.
67
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
Completion |
|
|
|
|
|
|
|
|
|
|
|
|
and |
|
and |
|
|
|
|
|
Total |
|
Corporate |
|
|
|
|
Evaluation |
|
Production |
|
WesternGeco |
|
Oilfield |
|
and Other |
|
Total |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
4,660.8 |
|
|
$ |
4,366.6 |
|
|
$ |
|
|
|
$ |
9,027.4 |
|
|
$ |
|
|
|
$ |
9,027.4 |
|
Equity in income of affiliates |
|
|
1.3 |
|
|
|
0.4 |
|
|
|
58.7 |
|
|
|
60.4 |
|
|
|
|
|
|
|
60.4 |
|
Segment profit |
|
|
1,248.1 |
|
|
|
947.8 |
|
|
|
58.7 |
|
|
|
2,254.6 |
|
|
|
1,482.2 |
|
|
|
3,736.8 |
|
Total assets |
|
|
3,988.8 |
|
|
|
3,595.7 |
|
|
|
|
|
|
|
7,584.5 |
|
|
|
1,121.2 |
|
|
|
8,705.7 |
|
Investment in affiliates |
|
|
7.3 |
|
|
|
12.7 |
|
|
|
|
|
|
|
20.0 |
|
|
|
|
|
|
|
20.0 |
|
Capital expenditures |
|
|
631.8 |
|
|
|
279.7 |
|
|
|
|
|
|
|
911.5 |
|
|
|
10.7 |
|
|
|
922.2 |
|
Depreciation and amortization |
|
|
274.5 |
|
|
|
134.8 |
|
|
|
|
|
|
|
409.3 |
|
|
|
24.4 |
|
|
|
433.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,694.2 |
|
|
$ |
3,490.0 |
|
|
$ |
|
|
|
$ |
7,184.2 |
|
|
$ |
1.3 |
|
|
$ |
7,185.5 |
|
Equity in income of affiliates |
|
|
1.1 |
|
|
|
2.2 |
|
|
|
96.7 |
|
|
|
100.0 |
|
|
|
0.1 |
|
|
|
100.1 |
|
Segment profit (loss) |
|
|
766.3 |
|
|
|
682.4 |
|
|
|
96.7 |
|
|
|
1,545.4 |
|
|
|
(266.2 |
) |
|
|
1,279.2 |
|
Total assets |
|
|
3,221.9 |
|
|
|
2,882.6 |
|
|
|
688.0 |
|
|
|
6,792.5 |
|
|
|
1,014.9 |
|
|
|
7,807.4 |
|
Investment in affiliates |
|
|
6.1 |
|
|
|
12.2 |
|
|
|
660.6 |
|
|
|
678.9 |
|
|
|
|
|
|
|
678.9 |
|
Capital expenditures |
|
|
347.8 |
|
|
|
129.6 |
|
|
|
|
|
|
|
477.4 |
|
|
|
0.9 |
|
|
|
478.3 |
|
Depreciation and amortization |
|
|
232.7 |
|
|
|
121.1 |
|
|
|
|
|
|
|
353.8 |
|
|
|
28.6 |
|
|
|
382.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
3,033.3 |
|
|
$ |
3,042.9 |
|
|
$ |
|
|
|
$ |
6,076.2 |
|
|
$ |
3.4 |
|
|
$ |
6,079.6 |
|
Equity in income (loss) of
affiliates |
|
|
0.4 |
|
|
|
1.9 |
|
|
|
34.5 |
|
|
|
36.8 |
|
|
|
(0.5 |
) |
|
|
36.3 |
|
Segment profit (loss) |
|
|
510.4 |
|
|
|
514.4 |
|
|
|
34.5 |
|
|
|
1,059.3 |
|
|
|
(283.4 |
) |
|
|
775.9 |
|
Total assets |
|
|
2,893.1 |
|
|
|
2,625.4 |
|
|
|
643.9 |
|
|
|
6,162.4 |
|
|
|
658.9 |
|
|
|
6,821.3 |
|
Investment in affiliates |
|
|
5.2 |
|
|
|
48.3 |
|
|
|
624.6 |
|
|
|
678.1 |
|
|
|
|
|
|
|
678.1 |
|
Capital expenditures |
|
|
236.4 |
|
|
|
110.4 |
|
|
|
|
|
|
|
346.8 |
|
|
|
1.4 |
|
|
|
348.2 |
|
Depreciation and amortization |
|
|
226.7 |
|
|
|
116.7 |
|
|
|
|
|
|
|
343.4 |
|
|
|
28.2 |
|
|
|
371.6 |
|
For the years ended December 31, 2006, 2005 and 2004, 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Corporate and other expenses |
|
$ |
(259.9 |
) |
|
$ |
(211.9 |
) |
|
$ |
(206.6 |
) |
Interest expense |
|
|
(68.9 |
) |
|
|
(72.3 |
) |
|
|
(83.6 |
) |
Interest and dividend income |
|
|
67.5 |
|
|
|
18.0 |
|
|
|
6.8 |
|
Gain on sale of interest in affiliate |
|
|
1,743.5 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,482.2 |
|
|
$ |
(266.2 |
) |
|
$ |
(283.4 |
) |
|
68
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
The following table presents the details of Corporate and Other total assets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Cash and other assets |
|
$ |
902.8 |
|
|
$ |
771.8 |
|
|
$ |
330.8 |
|
Accounts receivable |
|
|
8.8 |
|
|
|
9.3 |
|
|
|
26.5 |
|
Current deferred tax asset |
|
|
2.6 |
|
|
|
29.4 |
|
|
|
61.7 |
|
Property |
|
|
65.8 |
|
|
|
78.5 |
|
|
|
107.6 |
|
Other tangible assets |
|
|
141.2 |
|
|
|
109.3 |
|
|
|
115.6 |
|
Assets of discontinued operations |
|
|
|
|
|
|
16.6 |
|
|
|
16.7 |
|
|
Total |
|
$ |
1,121.2 |
|
|
$ |
1,014.9 |
|
|
$ |
658.9 |
|
|
The following table presents consolidated revenues by country based on the location of the use
of the products or services for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
United States |
|
$ |
3,392.5 |
|
|
$ |
2,576.1 |
|
|
$ |
2,132.9 |
|
Canada |
|
|
607.1 |
|
|
|
472.8 |
|
|
|
389.1 |
|
United Kingdom |
|
|
514.8 |
|
|
|
402.9 |
|
|
|
329.2 |
|
Norway |
|
|
438.4 |
|
|
|
376.1 |
|
|
|
310.7 |
|
Saudi Arabia |
|
|
391.3 |
|
|
|
170.6 |
|
|
|
89.3 |
|
China |
|
|
212.0 |
|
|
|
218.5 |
|
|
|
192.9 |
|
Venezuela |
|
|
190.1 |
|
|
|
176.8 |
|
|
|
163.3 |
|
Other countries |
|
|
3,281.2 |
|
|
|
2,791.7 |
|
|
|
2,472.2 |
|
|
Total |
|
$ |
9,027.4 |
|
|
$ |
7,185.5 |
|
|
$ |
6,079.6 |
|
|
The following table presents net property by country based on the location of the asset at
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
United States |
|
$ |
927.8 |
|
|
$ |
734.4 |
|
|
$ |
724.6 |
|
United Kingdom |
|
|
188.8 |
|
|
|
133.2 |
|
|
|
146.0 |
|
Canada |
|
|
78.8 |
|
|
|
67.9 |
|
|
|
56.4 |
|
Germany |
|
|
51.7 |
|
|
|
49.4 |
|
|
|
44.4 |
|
Norway |
|
|
50.7 |
|
|
|
43.8 |
|
|
|
46.8 |
|
United Arab Emirates |
|
|
44.3 |
|
|
|
29.0 |
|
|
|
15.4 |
|
Brazil |
|
|
34.3 |
|
|
|
21.0 |
|
|
|
18.8 |
|
Other countries |
|
|
424.1 |
|
|
|
276.8 |
|
|
|
279.8 |
|
|
Total |
|
$ |
1,800.5 |
|
|
$ |
1,355.5 |
|
|
$ |
1,332.2 |
|
|
69
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
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. In the U.S., we merged two pension plans effective
January 1, 2007, resulting in one tax-qualified U.S. pension plan, the Baker Hughes Incorporated
Pension Plan (BHIPP). Under the provisions of BHIPP, 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 BHIPP 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 and life insurance benefits (other postretirement
benefits), through an unfunded plan, to substantially all U.S. employees who retire and have met
certain age and service requirements.
Adoption of SFAS 158
In September 2006, the FASB issued SFAS 158, which 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 will be adopted on December
31, 2008, as allowed under SFAS 158.
The incremental effect of applying SFAS 158 on the individual line items in the balance sheet
as of December 31, 2006, is provided below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increases (Decreases) |
|
|
|
|
|
|
Before |
|
|
|
|
|
|
|
|
|
Other |
|
After |
|
|
Application |
|
|
|
|
|
Non-U.S. |
|
Postretirement |
|
Application |
|
|
of SFAS 158 |
|
U.S. Pensions |
|
Pensions |
|
Benefits |
|
of SFAS 158 |
|
Other assets |
|
$ |
479.2 |
|
|
$ |
(24.0 |
) |
|
$ |
(81.5 |
) |
|
$ |
6.3 |
|
|
$ |
380.0 |
|
Intangible assets |
|
|
190.5 |
|
|
|
(0.1 |
) |
|
|
|
|
|
|
|
|
|
|
190.4 |
|
Total assets |
|
$ |
8,805.0 |
|
|
$ |
(24.1 |
) |
|
$ |
(81.5 |
) |
|
$ |
6.3 |
|
|
$ |
8,705.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities for pensions and other
postretirement benefits |
|
$ |
399.0 |
|
|
$ |
(0.2 |
) |
|
$ |
(77.4 |
) |
|
$ |
17.9 |
|
|
$ |
339.3 |
|
Accumulated other comprehensive loss |
|
|
(147.6 |
) |
|
|
(23.9 |
) |
|
|
(4.1 |
) |
|
|
(11.6 |
) |
|
|
(187.2 |
) |
Total stockholders equity |
|
|
5,282.5 |
|
|
|
(23.9 |
) |
|
|
(4.1 |
) |
|
|
(11.6 |
) |
|
|
5,242.9 |
|
Total liabilities and stockholders equity |
|
$ |
8,805.0 |
|
|
$ |
(24.1 |
) |
|
$ |
(81.5 |
) |
|
$ |
6.3 |
|
|
$ |
8,705.7 |
|
In the table above, the incremental effect on other assets consists of a decrease of $120.8
million related to prepaid pension assets offset by an increase of $21.6 million related to
deferred tax assets. The incremental effect on accumulated other comprehensive loss (AOCL) is
net of the tax impact of $21.6 million.
70
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
plans, the benefit obligation is the accumulated postretirement benefit obligation (APBO). The
measurement date for plan assets and obligations are as of October 1 of each year presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
U.S. Pension |
|
|
Non-U.S. Pension |
|
|
Postretirement |
|
|
|
Benefits |
|
|
Benefits |
|
|
Benefits |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Change in benefit obligation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year |
|
$ |
238.8 |
|
|
$ |
203.8 |
|
|
$ |
287.5 |
|
|
$ |
261.0 |
|
|
$ |
184.5 |
|
|
$ |
169.5 |
|
Service cost |
|
|
26.2 |
|
|
|
22.8 |
|
|
|
3.4 |
|
|
|
2.2 |
|
|
|
7.4 |
|
|
|
6.1 |
|
Interest cost |
|
|
12.8 |
|
|
|
11.9 |
|
|
|
15.0 |
|
|
|
13.8 |
|
|
|
9.7 |
|
|
|
9.7 |
|
Actuarial (gain) loss |
|
|
(0.1 |
) |
|
|
10.9 |
|
|
|
24.6 |
|
|
|
47.8 |
|
|
|
(31.8 |
) |
|
|
12.5 |
|
Benefits paid |
|
|
(11.7 |
) |
|
|
(11.3 |
) |
|
|
(10.6 |
) |
|
|
(5.3 |
) |
|
|
(12.9 |
) |
|
|
(13.3 |
) |
Plan amendments |
|
|
6.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Curtailments/settlements (gain) loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.2 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
(2.5 |
) |
|
|
0.7 |
|
|
|
0.1 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
Exchange rate adjustments |
|
|
|
|
|
|
|
|
|
|
40.5 |
|
|
|
(31.0 |
) |
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year |
|
|
269.6 |
|
|
|
238.8 |
|
|
|
360.5 |
|
|
|
287.5 |
|
|
|
156.9 |
|
|
|
184.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year |
|
|
354.1 |
|
|
|
284.9 |
|
|
|
207.6 |
|
|
|
158.3 |
|
|
|
|
|
|
|
|
|
Actual return on plan assets |
|
|
39.7 |
|
|
|
45.9 |
|
|
|
23.3 |
|
|
|
30.7 |
|
|
|
|
|
|
|
|
|
Employer contributions |
|
|
30.6 |
|
|
|
34.6 |
|
|
|
22.3 |
|
|
|
45.6 |
|
|
|
12.9 |
|
|
|
13.3 |
|
Benefits paid |
|
|
(11.7 |
) |
|
|
(11.3 |
) |
|
|
(10.6 |
) |
|
|
(5.3 |
) |
|
|
(12.9 |
) |
|
|
(13.3 |
) |
Settlements (gain) loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.3 |
) |
|
|
|
|
|
|
|
|
Other |
|
|
(2.5 |
) |
|
|
|
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange rate adjustments |
|
|
|
|
|
|
|
|
|
|
30.6 |
|
|
|
(20.4 |
) |
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year |
|
|
410.2 |
|
|
|
354.1 |
|
|
|
273.3 |
|
|
|
207.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status over (under) at measurement date |
|
|
140.6 |
|
|
|
115.3 |
|
|
|
(87.2 |
) |
|
|
(79.9 |
) |
|
|
(156.9 |
) |
|
|
(184.5 |
) |
Employer contributions fourth quarter |
|
|
0.6 |
|
|
|
28.8 |
|
|
|
18.3 |
|
|
|
8.3 |
|
|
|
3.8 |
|
|
|
3.3 |
|
|
|
|
Funded status over (under) at end of year |
|
$ |
141.2 |
|
|
|
144.1 |
|
|
$ |
(68.9 |
) |
|
|
(71.6 |
) |
|
$ |
(153.1 |
) |
|
|
(181.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized actuarial loss, net |
|
|
|
|
|
|
47.8 |
|
|
|
|
|
|
|
95.1 |
|
|
|
|
|
|
|
45.4 |
|
Unrecognized prior service cost, net |
|
|
|
|
|
|
0.3 |
|
|
|
|
|
|
|
0.2 |
|
|
|
|
|
|
|
7.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized |
|
|
|
|
|
$ |
192.2 |
|
|
|
|
|
|
$ |
23.7 |
|
|
|
|
|
|
$ |
(128.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amounts recognized in the consolidated balance sheet consist of the following as of
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
U.S. Pension |
|
Non-U.S. Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
|
Benefits |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Noncurrent assets |
|
$ |
160.1 |
|
|
$ |
203.6 |
|
|
$ |
|
|
|
$ |
46.2 |
|
|
$ |
|
|
|
$ |
|
|
Current liabilities |
|
|
(2.3 |
) |
|
|
|
|
|
|
(0.6 |
) |
|
|
|
|
|
|
(13.8 |
) |
|
|
(15.5 |
) |
Noncurrent liabilities |
|
|
(16.6 |
) |
|
|
(11.4 |
) |
|
|
(68.3 |
) |
|
|
(22.5 |
) |
|
|
(139.3 |
) |
|
|
(113.1 |
) |
|
Net amount recognized |
|
$ |
141.2 |
|
|
$ |
192.2 |
|
|
$ |
(68.9 |
) |
|
$ |
23.7 |
|
|
$ |
(153.1 |
) |
|
$ |
(128.6 |
) |
|
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 |
|
2006 |
|
2005 |
|
Target |
|
2006 |
|
2005 |
|
Equity securities |
|
|
68 |
% |
|
|
68 |
% |
|
|
69 |
% |
|
|
55 |
% |
|
|
55 |
% |
|
|
58 |
% |
Debt securities |
|
|
25 |
% |
|
|
24 |
% |
|
|
21 |
% |
|
|
21 |
% |
|
|
28 |
% |
|
|
20 |
% |
Real estate |
|
|
7 |
% |
|
|
8 |
% |
|
|
9 |
% |
|
|
21 |
% |
|
|
12 |
% |
|
|
17 |
% |
Other |
|
|
|
|
|
|
|
|
|
|
1 |
% |
|
|
3 |
% |
|
|
5 |
% |
|
|
5 |
% |
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
71
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
We have an investment committee that meets quarterly to review the portfolio returns and
to determine asset-mix targets based on asset/liability studies. A third-party investment
consultant assisted us in developing an asset allocation strategy to determine our expected rate of
return and expected risk for various investment portfolios. The investment committee considered
these studies in the formal establishment of the current asset-mix targets based on the projected
risk and return levels for each asset class.
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 $260.9 million and $232.9 million at December 31, 2006 and 2005, respectively.
The ABO for all non-U.S. plans was $353.3 million and $279.2 million at December 31, 2006 and 2005,
respectively.
Information for the plans with ABOs in excess of plan assets is as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
U.S. Pension |
|
Non-U.S. Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
|
Benefits |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Projected benefit obligation |
|
$ |
19.5 |
|
|
$ |
108.0 |
|
|
$ |
355.1 |
|
|
$ |
281.7 |
|
|
|
n/a |
|
|
|
n/a |
|
Accumulated benefit obligation |
|
|
19.2 |
|
|
|
102.2 |
|
|
|
348.4 |
|
|
|
274.6 |
|
|
$ |
156.9 |
|
|
$ |
184.5 |
|
Fair value of plan assets |
|
|
|
|
|
|
77.9 |
|
|
|
268.1 |
|
|
|
203.0 |
|
|
|
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 |
|
|
U.S. Pension |
|
Non-U.S. Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
|
Benefits |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
Discount rate |
|
|
6.0 |
% |
|
|
5.5 |
% |
|
|
5.0 |
% |
|
|
4.9 |
% |
|
|
6.0 |
% |
|
|
5.5 |
% |
Rate of compensation increase |
|
|
4.0 |
% |
|
|
4.0 |
% |
|
|
3.9 |
% |
|
|
3.4 |
% |
|
|
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 (AOCL) consist of the
following as of December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
U.S. Pension |
|
Non-U.S. Pension |
|
Postretirement |
|
|
Benefits |
|
Benefits |
|
Benefits |
|
Net loss (gain) |
|
$ |
38.8 |
|
|
$ |
123.4 |
|
|
$ |
11.5 |
|
Net prior service cost (credit) |
|
|
6.4 |
|
|
|
0.2 |
|
|
|
6.4 |
|
Net transition obligation |
|
|
|
|
|
|
0.1 |
|
|
|
|
|
|
Total |
|
$ |
45.2 |
|
|
$ |
123.7 |
|
|
$ |
17.9 |
|
|
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 $3.3 million and $0.7 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 $1.0 million.
72
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 |
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
Service cost |
|
$ |
26.2 |
|
|
$ |
22.8 |
|
|
$ |
20.6 |
|
|
$ |
3.4 |
|
|
$ |
2.2 |
|
|
$ |
2.1 |
|
|
$ |
7.4 |
|
|
$ |
6.1 |
|
|
$ |
5.5 |
|
Interest cost |
|
|
12.8 |
|
|
|
11.9 |
|
|
|
10.6 |
|
|
|
15.0 |
|
|
|
13.8 |
|
|
|
12.7 |
|
|
|
9.7 |
|
|
|
9.7 |
|
|
|
9.6 |
|
Expected return on plan assets |
|
|
(31.6 |
) |
|
|
(25.9 |
) |
|
|
(20.7 |
) |
|
|
(16.0 |
) |
|
|
(13.2 |
) |
|
|
(9.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
0.1 |
|
|
|
|
|
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.8 |
|
|
|
0.6 |
|
|
|
0.6 |
|
Amortization of net (gain) loss |
|
|
0.8 |
|
|
|
2.6 |
|
|
|
4.0 |
|
|
|
2.6 |
|
|
|
2.6 |
|
|
|
4.6 |
|
|
|
2.1 |
|
|
|
2.0 |
|
|
|
1.0 |
|
Special termination benefit cost |
|
|
|
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement/curtailments (gain) loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2 |
|
|
|
(3.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
8.3 |
|
|
$ |
12.1 |
|
|
$ |
14.6 |
|
|
$ |
5.0 |
|
|
$ |
5.6 |
|
|
$ |
7.0 |
|
|
$ |
20.0 |
|
|
$ |
18.4 |
|
|
$ |
16.7 |
|
|
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 |
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
Discount rate |
|
|
5.5 |
% |
|
|
6.0 |
% |
|
|
6.3 |
% |
|
|
4.9 |
% |
|
|
5.7 |
% |
|
|
5.4 |
% |
|
|
5.5 |
% |
|
|
6.0 |
% |
|
|
6.3 |
% |
Expected rate of return on
plan assets |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
8.5 |
% |
|
|
6.9 |
% |
|
|
7.4 |
% |
|
|
7.3 |
% |
|
|
n/a |
|
|
|
n/a |
|
|
|
n/a |
|
Rate of compensation increase |
|
|
4.0 |
% |
|
|
3.5 |
% |
|
|
3.5 |
% |
|
|
3.5 |
% |
|
|
3.5 |
% |
|
|
2.5 |
% |
|
|
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. As a result of
the merger of our U.S. plans, BHIPP is overfunded; therefore, we are not required nor do we intend
to make pension contributions to BHIPP in 2007, and we currently estimate that we will not be
required to make contributions to BHIPP for five to eight years thereafter. In 2007, we expect to
contribute between $2.0 million and $3.0 million to our nonqualified U.S. pension plans and between
$13.0 million and $15.0 million to the non-U.S. pension plans.
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 $2.0 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 |
|
2007 |
|
$ |
14.2 |
|
|
$ |
10.9 |
|
|
$ |
14.3 |
|
2008 |
|
|
15.0 |
|
|
|
10.9 |
|
|
|
14.8 |
|
2009 |
|
|
16.9 |
|
|
|
11.7 |
|
|
|
15.3 |
|
2010 |
|
|
19.1 |
|
|
|
9.8 |
|
|
|
15.6 |
|
2011 |
|
|
22.0 |
|
|
|
9.9 |
|
|
|
16.1 |
|
2012-2016 |
|
|
166.2 |
|
|
|
31.3 |
|
|
|
93.4 |
|
73
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 the
postretirement welfare benefits plan. As of December 31, 2006, the health care cost trend rate was
9.0% for employees under age 65 and 6.6% for participants over age 65, with each declining
gradually each successive year until it reaches 5.0% for both employees under age 65 and over age
65 in 2011. A one percentage point change in assumed health care cost trend rates would have had
the following effects on 2006:
|
|
|
|
|
|
|
|
|
|
|
One Percentage |
|
One Percentage |
|
|
Point Increase |
|
Point Decrease |
|
Effect on total of service and interest cost components |
|
$ |
0.6 |
|
|
$ |
(0.5 |
) |
Effect on postretirement welfare benefit obligation |
|
|
10.0 |
|
|
|
(8.9 |
) |
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. 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. Beginning January 1, 2007, we will match
employee contributions in cash at the rate of $1.00 per $1.00 employee contribution for the first
5% of the employees salary. 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. Prior to January 1, 2007, such contributions become fully vested to the employee
after five years of employment. Beginning January 1, 2007, 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. Our contributions to the Thrift Plan and several other
non-U.S. defined contribution plans amounted to $102.2 million, $86.5 million and $75.5 million in
2006, 2005 and 2004, 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 $8.3 million, $7.2 million and $6.1 million for 2006, 2005 and 2004,
respectively.
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,
2006 and 2005 was $17.6 million and $17.5 million, respectively, and is included in other
liabilities in our consolidated balance sheet.
NOTE 15. COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2006, 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, 2011 are $82.0 million,
$57.4 million, $40.8 million, $28.5 million and $21.6 million, respectively, and $137.9 million in
the aggregate thereafter. We have not entered into any significant capital leases.
74
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 related to these
types of claims. 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 March 29, 2002, we announced that we had been advised that the Securities and Exchange
Commission (SEC) and the Department of Justice (DOJ) are conducting investigations into
allegations of violations of law relating to Nigeria and other related matters. The SEC has issued
a formal order of investigation into possible violations of provisions under the Foreign Corrupt
Practices Act (FCPA) regarding anti-bribery, books and records and internal controls. The SEC
has 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 ongoing
investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ
and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former
employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In
addition, we have conducted internal investigations into these matters.
Our internal investigations have 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 Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental
authorities in Nigeria. The investigation in Nigeria was substantially completed during the first
quarter of 2003 and, based upon current information, we do not expect that any such potential
liabilities will have a material adverse effect on our consolidated financial statements. The
internal investigations in Angola and Kazakhstan were substantially completed in the third quarter
of 2004. Evidence obtained during the course of the investigations has been provided to the SEC
and DOJ.
In
2004, we received a subpoena from a grand jury in the Southern District of New York regarding
goods and services we delivered to Iraq from 1995 through 2003 during the United Nations
Oil-for-Food Program. In 2004, we also received a request from the SEC to provide a written statement
and certain information regarding our participation in that program. We have responded to both the
subpoena and the request and may provide additional materials.
The DOJ, the SEC and other agencies and authorities have a broad range of civil and criminal
sanctions they may seek to impose against corporations and individuals in appropriate circumstances
including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications
to business practices and compliance programs. Such agencies and authorities have entered into
agreements with, and obtained a range of sanctions against, several public corporations and
individuals arising from allegations of improper payments and deficiencies in books and records and
internal controls, whereby civil and criminal penalties were imposed, including in some cases
multi-million dollar fines and other sanctions.
The Company has engaged in settlement discussions with both the DOJ and SEC concerning the
issues in Nigeria, Angola and Kazakhstan. There can be no assurance that such discussions will
result in a resolution of any or all of these issues; however, we have determined that the
settlement discussions are likely to result in a resolution that will include both civil and
criminal sanctions as well as significant fines and penalties. Our best estimate of the associated
financial charge of $46.1 million was recorded in the fourth quarter of 2006 and is included in
selling, general and administrative expenses. If a resolution is not concluded, we believe it is
probable that the DOJ and SEC will seek civil and criminal sanctions against us as well as fines
and penalties. If ultimately imposed, or if agreed to by settlement, such fines and penalties may
exceed the current amount we have estimated and reserved. It is not possible to accurately predict
at this time when any of the investigations will be finally resolved.
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 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.
75
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
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 $17.3 million and $17.4 million, which
includes accruals of $5.9 million and $4.9 million for the various Superfund sites, at December 31,
2006 and 2005, 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 $376.9 million at December 31, 2006. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts of approximately $253.7 million at December 31, 2006. 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.
NOTE 16. OTHER SUPPLEMENTAL INFORMATION
Product Warranty Liability
The changes in the aggregate product warranty liability are as follows:
|
|
|
|
|
|
Balance as of December 31, 2004 |
|
$ |
16.6 |
|
Claims paid |
|
|
(2.6 |
) |
Additional warranties |
|
|
2.1 |
|
Revisions in estimates for previously issued warranties |
|
|
(2.5 |
) |
Other |
|
|
(0.2 |
) |
|
Balance as of December 31, 2005 |
|
|
13.4 |
|
Claims paid |
|
|
(6.3 |
) |
Additional warranties |
|
|
11.4 |
|
Revisions in estimates for previously issued warranties |
|
|
3.0 |
|
Other |
|
|
1.1 |
|
|
Balance as of December 31, 2006 |
|
$ |
22.6 |
|
|
76
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Asset Retirement Obligations
On December 31, 2005, we adopted FASB Interpretation No. 47, Conditional Asset Retirement
Obligations (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligation
as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation
to perform an asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the entity. The
obligation to perform the asset retirement activity is unconditional even though uncertainty exists
about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have
sufficient information to reasonably estimate the fair value of an asset retirement obligation.
The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded
as the cumulative effect of accounting change in the consolidated statement of operations. In
conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million
as the fair value of the costs associated with the special handling of asbestos related materials
in certain facilities.
We have certain facilities that contain asbestos related materials for which a liability has
not been recognized because we are unable to determine the time frame over which these obligations
may be settled. Our normal practice is to conduct asbestos abatement procedures when required by
contractual requirements related to asset disposals or when a facility with asbestos is subject to
significant renovation or is demolished. We have no plans or expectations to sell, abandon or
demolish these other facilities nor do we anticipate the need for major renovations to them
resulting from technological or operations changes or other factors. We expect these other
facilities to be operational in their current state for the foreseeable future and, therefore, the
time frame over which these obligations will be settled cannot be determined. As a result,
sufficient information does not exist to enable us to reasonably estimate the fair value of the
asset retirement obligation.
The changes in the asset retirement obligation liability are as follows:
|
|
|
|
|
|
Balance as of December 31, 2004 |
|
$ |
12.9 |
|
Liabilities incurred |
|
|
1.6 |
|
Liabilities settled |
|
|
(0.2 |
) |
Accretion expense |
|
|
0.5 |
|
Revisions to existing liabilities |
|
|
1.2 |
|
Adoption of FIN 47 |
|
|
1.6 |
|
Translation adjustments |
|
|
(0.2 |
) |
|
Balance as of December 31, 2005 |
|
|
17.4 |
|
Liabilities incurred |
|
|
1.3 |
|
Liabilities settled |
|
|
(1.2 |
) |
Accretion expense |
|
|
0.3 |
|
Revisions to existing liabilities |
|
|
(2.3 |
) |
Translation adjustments |
|
|
0.2 |
|
|
Balance as of December 31, 2006 |
|
$ |
15.7 |
|
|
Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss, net of tax, is comprised of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
Foreign currency translation adjustments |
|
$ |
(60.3 |
) |
|
$ |
(117.4 |
) |
Pension and other postretirement benefits |
|
|
(126.9 |
) |
|
|
(69.5 |
) |
Other |
|
|
|
|
|
|
(1.1 |
) |
|
Total |
|
$ |
(187.2 |
) |
|
$ |
(188.0 |
) |
|
77
Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Other
Supplemental consolidated statement of operations information is as follows for the years ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
Rental expense (generally
transportation equipment and
warehouse facilities) |
|
$ |
161.0 |
|
|
$ |
138.7 |
|
|
$ |
123.5 |
|
Research and development |
|
|
216.2 |
|
|
|
188.2 |
|
|
|
176.7 |
|
NOTE 17. QUARTERLY DATA (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
|
Year |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
2,062.0 |
|
|
$ |
2,203.3 |
|
|
$ |
2,309.4 |
|
|
$ |
2,452.7 |
|
|
$ |
9,027.4 |
|
Gross profit (1) |
|
|
712.5 |
|
|
|
780.7 |
|
|
|
851.1 |
|
|
|
900.7 |
|
|
|
3,245.0 |
|
Income from continuing operations |
|
|
318.8 |
|
|
|
1,395.0 |
|
|
|
358.6 |
|
|
|
326.2 |
|
|
|
2,398.6 |
|
Net income |
|
|
339.2 |
|
|
|
1,395.0 |
|
|
|
358.6 |
|
|
|
326.2 |
|
|
|
2,419.0 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
0.93 |
|
|
|
4.15 |
|
|
|
1.10 |
|
|
|
1.02 |
|
|
|
7.26 |
|
Net income |
|
|
0.99 |
|
|
|
4.15 |
|
|
|
1.10 |
|
|
|
1.02 |
|
|
|
7.32 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
0.93 |
|
|
|
4.14 |
|
|
|
1.09 |
|
|
|
1.02 |
|
|
|
7.21 |
|
Net income |
|
|
0.99 |
|
|
|
4.14 |
|
|
|
1.09 |
|
|
|
1.02 |
|
|
|
7.27 |
|
Dividends per share |
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.13 |
|
|
|
0.52 |
|
Common stock market prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
77.44 |
|
|
|
88.60 |
|
|
|
83.65 |
|
|
|
78.25 |
|
|
|
|
|
Low |
|
|
63.93 |
|
|
|
67.75 |
|
|
|
62.17 |
|
|
|
66.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,642.9 |
|
|
$ |
1,768.4 |
|
|
$ |
1,784.8 |
|
|
$ |
1,989.4 |
|
|
$ |
7,185.5 |
|
Gross profit (1) |
|
|
487.3 |
|
|
|
552.6 |
|
|
|
564.8 |
|
|
|
638.3 |
|
|
|
2,243.0 |
|
Income from continuing operations |
|
|
178.4 |
|
|
|
218.0 |
|
|
|
220.6 |
|
|
|
257.4 |
|
|
|
874.4 |
|
Net income |
|
|
179.8 |
|
|
|
218.8 |
|
|
|
221.9 |
|
|
|
257.9 |
|
|
|
878.4 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
0.53 |
|
|
|
0.65 |
|
|
|
0.64 |
|
|
|
0.76 |
|
|
|
2.58 |
|
Net income |
|
|
0.53 |
|
|
|
0.65 |
|
|
|
0.65 |
|
|
|
0.76 |
|
|
|
2.59 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
0.53 |
|
|
|
0.64 |
|
|
|
0.64 |
|
|
|
0.75 |
|
|
|
2.56 |
|
Net income |
|
|
0.53 |
|
|
|
0.64 |
|
|
|
0.65 |
|
|
|
0.75 |
|
|
|
2.57 |
|
Dividends per share |
|
|
0.115 |
|
|
|
0.115 |
|
|
|
0.115 |
|
|
|
0.13 |
|
|
|
0.475 |
|
Common stock market prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
47.70 |
|
|
|
51.95 |
|
|
|
60.79 |
|
|
|
62.76 |
|
|
|
|
|
Low |
|
|
41.20 |
|
|
|
42.51 |
|
|
|
51.54 |
|
|
|
51.20 |
|
|
|
|
|
|
|
|
(1) |
|
Represents revenues less cost of sales, cost of services and rentals and research
and engineering. |
78
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
Our management has established and maintains a system of disclosure controls and procedures to
provide reasonable assurances that information required to be disclosed by us in the reports that
we file or submit under the Exchange Act is recorded, processed, summarized and reported within the
time periods specified in the SECs rules and forms. As of December 31, 2006, our management,
including our principal executive officer and principal financial officer, conducted an evaluation
of our disclosure controls and procedures. Based on this evaluation, our principal executive
officer and our principal financial officer concluded that our disclosure controls and procedures
as of December 31, 2006 are effective, at a reasonable assurance level, in ensuring that the
information required to be disclosed by us in reports filed under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the rules and forms of the
SEC.
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 as part of this Annual
Report on Form 10-K for the fiscal year ended December 31, 2006. Our managements assessment of the
effectiveness of our internal control over financial reporting as of December 31, 2006 has been
audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in
their report which is included herein. Managements report and the independent registered public
accounting firms attestation report are included in Item 8 under the captions 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, 2006 that has materially affected, or is reasonably likely to materially affect,
our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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 26, 2007
(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 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.
79
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, 2006 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 |
|
|
|
|
|
|
|
|
|
|
Remaining Available |
|
|
Number of |
|
|
|
|
|
for Future Issuance |
|
|
Securities to be |
|
|
|
|
|
Under Equity |
|
|
Issued Upon |
|
Weighted Average |
|
Compensation Plans |
|
|
Exercise of |
|
Exercise Price of |
|
(excluding |
|
|
Outstanding |
|
Outstanding |
|
securities |
|
|
Options, Warrants |
|
Options, Warrants |
|
reflected in the |
Equity Compensation Plan Category |
|
and Rights |
|
and Rights |
|
first column) |
|
Stockholder-approved plans (excluding
Employee Stock Purchase Plan) |
|
|
1.3 |
|
|
$ |
52.34 |
|
|
|
3.5 |
|
Nonstockholder-approved plans (1) |
|
|
3.0 |
|
|
|
43.84 |
|
|
|
6.7 |
|
|
Subtotal (except for weighted average
exercise price) |
|
|
4.3 |
|
|
|
46.39 |
|
|
|
10.2 |
|
Employee Stock Purchase Plan |
|
|
|
|
|
|
(2) |
|
|
|
2.9 |
|
|
Total |
|
|
4.3 |
(3) |
|
|
|
|
|
|
13.1 |
|
|
|
|
|
(1) |
|
The table includes the following nonstockholder-approved plans: the 1998 Employee
Stock Option Plan, the 1998 Special 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 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. |
|
(3) |
|
The table does not include shares subject to outstanding options we assumed in
connection with certain mergers and acquisitions of entities which originally granted those
options. When we acquired the stock of Western Atlas Inc. in a transaction completed in
August 1998, we assumed the options granted under the Western Atlas Director Stock Option
Plan. As of December 31, 2006, 5,400 shares of our common stock would be issuable upon the
exercise of outstanding options previously granted under the Western Atlas Director Stock
Option Plan with a weighted average exercise price per share of $33.15. |
80
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
is 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,
2006, options covering approximately 0.3 million shares of our common stock were outstanding under
the 1998 ESOP, options covering approximately 0.2 million shares were exercised during fiscal year
2006 and approximately 0.3 million shares remained available for future options.
1998 Special Employee Stock Option Plan
The Baker Hughes Incorporated 1998 Special Employee Stock Option Plan (the 1998 SESOP) was
adopted effective as of October 22, 1997. The number of shares authorized for issuance upon the
exercise of options granted under the 1998 SESOP is 2.5 million shares. Under the 1998 SESOP, the
Compensation Committee of our Board of Directors has the authority to grant nonqualified stock
options to purchase shares of our common stock to a broad-based group of employees. The exercise
price of the options will be equal to the fair market value per share of our common stock at the
time of the grant, and option terms may be up to ten years. Stock option grants of 100 shares,
with an exercise price of $47.813 per share, were issued to all of our U.S. employees in October
1997 and to our international employees in May 1998. As of December 31, 2006, options covering
approximately 0.3 million shares of our common stock were outstanding under the 1998 SESOP, options
covering approximately 0.2 million shares were exercised during fiscal year 2006 and approximately
1.6 million shares remained available for future options.
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 3.0 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, 2006, options covering approximately 2.4 million
shares of our common stock were outstanding under the 2002 Employee LTIP, options covering
approximately 0.7 million shares were exercised during fiscal year 2006 and approximately 4.3
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 $10.0
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).
81
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.
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, 2006, options
covering 3,313 shares of our common stock were outstanding under the Deferral Plan, options
covering 878 shares were exercised during fiscal 2006 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 section entitled Corporate
Governance-Director Independence in our Proxy Statement, which section is 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.
82
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) |
|
List of Documents filed as part of this Report. |
All financial statements of the Registrant as set forth under Item 8 of this Annual Report on
Form 10-K.
|
(2) |
|
Financial Statement Schedules |
Schedule II Valuation and Qualifying Accounts
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.
|
|
|
3.1
|
|
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, 2002). |
|
|
|
3.2
|
|
Certificate of Amendment to the Restated Certificate of Incorporation (filed as
Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4,
2005). |
|
|
|
3.3
|
|
Bylaws of Baker Hughes Incorporated restated as of April 27, 2006 (filed as
Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended March 31, 2006). |
|
|
|
4.1
|
|
Rights of Holders of the Companys Long-Term Debt. The Company has no long-term
debt instrument with regard to which the securities authorized thereunder 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. |
|
|
|
4.2
|
|
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, 2002). |
|
|
|
4.3
|
|
Certificate of Amendment to the Restated Certificate of Incorporation (filed as
Exhibit 3.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed May 4,
2005). |
|
|
|
4.4
|
|
Bylaws of Baker Hughes Incorporated restated as of April 27, 2006 (filed as
Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended March 31, 2006). |
|
|
|
4.5
|
|
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). |
|
|
|
10.1+
|
|
Employment Agreement by and between Baker Hughes Incorporated and Chad C. Deaton
dated as of October 25, 2004 (filed as Exhibit 10.3 to Current Report of Baker Hughes
Incorporated on Form 8-K filed October 7, 2004). |
|
|
|
10.2+
|
|
Change in Control Agreement between Baker Hughes Incorporated and Chad C. Deaton
dated as of October 25, 2004 (filed as Exhibit 10.2 to Current Report of Baker Hughes
Incorporated on Form 8-K filed October 7, 2004). |
|
|
|
10.3+
|
|
Indemnification Agreement dated as of October 25, 2004 between Baker Hughes
Incorporated and Chad C. Deaton (filed as Exhibit 10.1 to Current Report of Baker Hughes
Incorporated on Form 8-K filed on October 7, 2004). |
83
|
|
|
10.4+
|
|
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). |
|
|
|
10.5+
|
|
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). |
|
|
|
10.6+
|
|
Agreement regarding restricted stock award issued to James R. Clark on October
27, 2004 in the amount of 40,000 shares of Baker Hughes Incorporated Common Stock (filed
as Exhibit 10.7 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the
quarter ended September 30, 2004). |
|
|
|
10.7+
|
|
Second Amended and Restated Stock Matching Agreement by and between Baker Hughes
Incorporated and James R. Clark dated as of October 25, 2004 (filed as Exhibit 10.6 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended
September 30, 2004). |
|
|
|
10.8+
|
|
Letter dated October 26, 2005 to James R. Clark clarifying Mr. Clarks
employment terms (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated
on Form 10-Q for the quarter ended September 30, 2005). |
|
|
|
10.9+
|
|
Restated Retirement and Consulting Agreement between G. Stephen Finley and Baker
Hughes Incorporated dated as of March 27, 2006 (filed as Exhibit 10.2 to Current Report
on Form 8-K filed March 31, 2006). |
|
|
|
10.10+
|
|
Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated dated as of
March 27, 2006 (filed as Exhibit 10.1 to Current Report on Form 8-K filed March 31,
2006). |
|
|
|
10.11+
|
|
Form of Change in Control Severance Plan (filed as Exhibit 10.8 to Annual Report of
Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003). |
|
|
|
10.12+
|
|
Form of Change in Control Severance Agreement between Baker Hughes Incorporated and
David H. Barr and John A. ODonnell effective as of July 28, 2004, and with James R.
Clark, Alan R. Crain, Jr., Greg Nakanishi and Douglas J. Wall to be effective as of
January 1, 2006 and with Chris P. Beaver, Paul S. Butero and Martin S. Craighead
effective as of February 28, 2005 and with Richard L. Williams effective as of May 2,
2005 and with Charles S. Wolley effective as of January 1, 2006 and with Gary G. Rich
effective as of September 15, 2006 (filed as Exhibit 10.8 to Quarterly Report of Baker
Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004). |
|
|
|
10.13+
|
|
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). |
|
|
|
10.14+
|
|
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). |
|
|
|
10.15+
|
|
Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated
effective as of July 24, 2002 (filed as Exhibit 10.16 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2002). |
|
|
|
10.16+
|
|
Baker Hughes Incorporated Executive Severance Plan (effective November 1, 2002) (filed
as Exhibit 10.13 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year
ended December 31, 2002). |
|
|
|
10.17+
|
|
Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended and restated
effective January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes
Incorporated 10-Q for the quarter ended March 31, 2006). |
|
|
|
10.18+
|
|
Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated
effective as of January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker
Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005). |
84
|
|
|
10.19+*
|
|
First Amendment to Baker Hughes Incorporated Supplemental Retirement Plan, as amended
and restated effective as of January 1, 2005, dated February 9, 2007 to be effective
January 1, 2007. |
|
|
|
10.20+
|
|
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). |
|
|
|
10.21+
|
|
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). |
|
|
|
10.22+
|
|
Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4
to Registration Statement No. 333-87372 on Form S-8 filed May 1, 2002). |
|
|
|
10.23+
|
|
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). |
|
|
|
10.24+
|
|
Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October
27, 2005 (filed as Exhibit 10.3 to Quarterly Report on Form 10-Q for the quarter ended
September 30, 2005). |
|
|
|
10.25
|
|
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). |
|
|
|
10.26+
|
|
Baker Hughes Incorporated Pension Plan effective as of January 1, 2002, as amended by
First Amendment, effective January 1, 2002 (filed as Exhibit 10.51 to Annual Report of
Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002). |
|
|
|
10.27+
|
|
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). |
|
|
|
10.28+
|
|
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). |
|
|
|
10.29+
|
|
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). |
|
|
|
10.30
|
|
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). |
|
|
|
10.31
|
|
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). |
|
|
|
10.32+
|
|
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). |
|
|
|
10.33+
|
|
Form of Baker Hughes Incorporated Performance Award Agreement, including Terms and
Conditions for certain executive officers (filed as Exhibit 10.4 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004). |
|
|
|
10.34+
|
|
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). |
|
|
|
10.35+
|
|
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). |
85
|
|
|
10.36+
|
|
Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed
as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004). |
|
|
|
10.37
|
|
Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as
Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004). |
|
|
|
10.38
|
|
Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions
(filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31,
2004). |
|
|
|
10.39+
|
|
Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and
Conditions for directors (filed as Exhibit 10.40 to Annual Report on Form 10-K for the
year ended December 31, 2005). |
|
|
|
10.40+
|
|
Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and
Conditions for directors (filed as Exhibit 10.41 to Annual Report on Form 10-K for the
year ended December 31, 2005). |
|
|
|
10.41+*
|
|
Baker Hughes Incorporated Amended and Restated Nonqualified Stock Option Agreement
dated February 24, 2006 between Baker Hughes Incorporated and Anthony G. Fernandes. |
|
|
|
10.42+
|
|
Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms
and Conditions (filed as Exhibit 10.42 to Annual Report on Form 10-K for the year ended
December 31, 2005). |
|
|
|
10.43+
|
|
Performance Goals for the Performance Unit Award granted in 2006 (filed as Exhibit
10.43 to Annual Report on Form 10-K for the year ended December 31, 2005). |
|
|
|
10.44+*
|
|
Form of Performance Goals for the
Performance Unit Awards. |
|
|
|
10.45+*
|
|
Compensation Table for Named Executive Officers and Directors. |
|
|
|
10.46
|
|
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). |
|
|
|
10.47
|
|
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 June
12, 2006). |
|
|
|
10.48
|
|
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). |
|
|
|
10.49
|
|
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). |
|
|
|
10.50+
|
|
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). |
|
|
|
10.51
|
|
Master Formation Agreement by and among the Company, Schlumberger Limited and
certain wholly owned subsidiaries of Schlumberger Limited dated as of September 6, 2000
(filed as Exhibit 2.1 to Current Report of Baker Hughes Incorporated on Form 8-K dated
September 7, 2000). |
|
|
|
10.52
|
|
Master Sales Agreement by and among Schlumberger Limited, Baker Hughes
Incorporated and the other parties listed on the signature pages thereto dated as of
April 20, 2006 (filed as Exhibit 2.1 to Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended March 31, 2006). |
|
|
|
21.1*
|
|
Subsidiaries of Registrant. |
|
|
|
23.1*
|
|
Consent of Deloitte & Touche LLP. |
86
|
|
|
31.1*
|
|
Certification of Chad C. Deaton, Chief Executive Officer, dated February 23,
2007, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended. |
|
|
|
31.2*
|
|
Certification of Peter A. Ragauss, Chief Financial Officer, dated February 23,
2007, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended. |
|
|
|
32*
|
|
Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief
Financial Officer, dated February 23, 2007, furnished pursuant to Rule 13a-14(b) of the
Securities Exchange Act of 1934, as amended. |
|
|
|
99.1
|
|
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). |
87
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.
|
|
|
|
|
|
BAKER HUGHES INCORPORATED
|
|
Date: February 23, 2007 |
/s/ CHAD C. DEATON
|
|
|
Chad C. Deaton |
|
|
Chairman of the Board and Chief Executive Officer |
|
88
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 |
|
Title |
|
Date |
|
|
|
|
|
/s/ CHAD C. DEATON
(Chad C. Deaton)
|
|
Chairman of the Board and Chief Executive Officer
(principal executive officer)
|
|
February 23, 2007 |
|
|
|
|
|
/s/ PETER A. RAGAUSS
(Peter A. Ragauss)
|
|
Senior Vice President and Chief Financial Officer
(principal financial officer)
|
|
February 23, 2007 |
|
|
|
|
|
/s/ ALAN J. KEIFER
(Alan J. Keifer)
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Vice President and Controller
(principal accounting officer)
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February 23, 2007 |
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Director
|
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February 23, 2007 |
(Larry D. Brady) |
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/s/ CLARENCE P. CAZALOT, JR.
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Director
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February 23, 2007 |
(Clarence P. Cazalot, Jr.) |
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Director
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February 23, 2007 |
(Edward P. Djerejian) |
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Director
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February 23, 2007 |
(Anthony G. Fernandes) |
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Director
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February 23, 2007 |
(Claire W. Gargalli) |
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Director
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February 23, 2007 |
(Pierre H. Jungels) |
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Director
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February 23, 2007 |
(James A. Lash) |
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Director
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February 23, 2007 |
(James F. McCall) |
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Director
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February 23, 2007 |
(J. Larry Nichols) |
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Director
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February 23, 2007 |
(H. John Riley, Jr.) |
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Director
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February 23, 2007 |
(Charles L. Watson) |
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89
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 |
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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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to 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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Write-offs (2) |
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Accounts (3) |
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Period |
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Year ended December 31, 2006: |
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Reserve for doubtful accounts receivable |
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$ |
51.4 |
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$ |
27.5 |
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$ |
(20.2 |
) |
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$ |
(11.3 |
) |
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$ |
3.1 |
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$ |
50.5 |
|
Reserve for inventories |
|
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201.3 |
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|
44.9 |
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(38.8 |
) |
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4.3 |
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211.7 |
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Year ended December 31, 2005: |
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|
|
|
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|
|
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|
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|
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Reserve for doubtful accounts receivable |
|
|
50.2 |
|
|
|
28.3 |
|
|
|
(14.8 |
) |
|
|
(8.0 |
) |
|
|
(4.3 |
) |
|
|
51.4 |
|
Reserve for inventories |
|
|
220.0 |
|
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|
31.4 |
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|
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|
(42.1 |
) |
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|
(8.0 |
) |
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201.3 |
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Year ended December 31, 2004: |
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|
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|
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Reserve for doubtful accounts receivable |
|
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61.6 |
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21.1 |
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(19.3 |
) |
|
|
(14.4 |
) |
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1.2 |
|
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50.2 |
|
Reserve for inventories |
|
|
231.5 |
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38.8 |
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|
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|
(59.3 |
) |
|
|
9.0 |
|
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220.0 |
|
|
|
|
(1) |
|
Represents the reversals of prior accruals as receivables are collected. |
|
(2) |
|
Represents the elimination of accounts receivable and inventory deemed uncollectible
or worthless. |
|
(3) |
|
Represents reclasses, currency translation adjustments and divestitures. |
90
Index to 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, 2002). |
|
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3.2
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Certificate of Amendment to the Restated Certificate of
Incorporation (filed as Exhibit 3.1 to Current Report of Baker
Hughes Incorporated on Form 8-K filed May 4, 2005). |
|
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3.3
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|
Bylaws of Baker Hughes Incorporated restated as of April 27, 2006
(filed as Exhibit 3.2 to Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended March 31, 2006). |
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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 thereunder 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, 2002). |
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4.3
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Certificate of Amendment to the Restated Certificate of
Incorporation (filed as Exhibit 3.1 to Current Report of Baker
Hughes Incorporated on Form 8-K filed May 4, 2005). |
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4.4
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Bylaws of Baker Hughes Incorporated restated as of April 27, 2006
(filed as Exhibit 3.2 to Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended March 31, 2006). |
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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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10.1+
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|
Employment Agreement by and between Baker Hughes Incorporated and
Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit
10.3 to Current Report of Baker Hughes Incorporated on Form 8-K
filed October 7, 2004). |
|
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10.2+
|
|
Change in Control Agreement between Baker Hughes Incorporated and
Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit
10.2 to Current Report of Baker Hughes Incorporated on Form 8-K
filed October 7, 2004). |
|
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10.3+
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|
Indemnification Agreement dated as of October 25, 2004 between
Baker Hughes Incorporated and Chad C. Deaton (filed as Exhibit
10.1 to Current Report of Baker Hughes Incorporated on Form 8-K
filed on October 7, 2004). |
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10.4+
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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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10.5+
|
|
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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10.6+
|
|
Agreement regarding restricted stock award issued to James R.
Clark on October 27, 2004 in the amount of 40,000 shares of Baker
Hughes Incorporated Common Stock (filed as Exhibit 10.7 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for
the quarter ended September 30, 2004). |
91
|
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10.7+
|
|
Second Amended and Restated Stock Matching Agreement by and
between Baker Hughes Incorporated and James R. Clark dated as of
October 25, 2004 (filed as Exhibit 10.6 to Quarterly Report of
Baker Hughes Incorporated on Form 10-Q for the quarter ended
September 30, 2004). |
|
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10.8+
|
|
Letter dated October 26, 2005 to James R. Clark clarifying Mr.
Clarks employment terms (filed as Exhibit 10.2 to Quarterly
Report of Baker Hughes Incorporated on Form 10-Q for the quarter
ended September 30, 2005). |
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10.9+
|
|
Restated Retirement and Consulting Agreement between G. Stephen
Finley and Baker Hughes Incorporated dated as of March 27, 2006
(filed as Exhibit 10.2 to Current Report on Form 8-K filed March
31, 2006). |
|
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10.10+
|
|
Letter Agreement between Peter A. Ragauss and Baker Hughes
Incorporated dated as of March 27, 2006 (filed as Exhibit 10.1 to
Current Report on Form 8-K filed March 31, 2006). |
|
|
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10.11+
|
|
Form of Change in Control Severance Plan (filed as Exhibit 10.8
to Annual Report of Baker Hughes Incorporated on Form 10-K for
the year ended December 31, 2003). |
|
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10.12+
|
|
Form of Change in Control Severance Agreement between Baker
Hughes Incorporated and David H. Barr and John A. ODonnell
effective as of July 28, 2004, and with James R. Clark, Alan R.
Crain, Jr., Greg Nakanishi and Douglas J. Wall to be effective as
of January 1, 2006 and with Chris P. Beaver, Paul S. Butero and
Martin S. Craighead effective as of February 28, 2005 and with
Richard L. Williams effective as of May 2, 2005 and with Charles
S. Wolley effective as of January 1, 2006 and with Gary G. Rich
effective as of September 15, 2006 (filed as Exhibit 10.8 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for
the quarter ended September 30, 2004). |
|
|
|
10.13+
|
|
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). |
|
|
|
10.14+
|
|
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). |
|
|
|
10.15+
|
|
Baker Hughes Incorporated Director Compensation Deferral Plan, as
amended and restated effective as of July 24, 2002 (filed as
Exhibit 10.16 to Annual Report of Baker Hughes Incorporated on
Form 10-K for the year ended December 31, 2002). |
|
|
|
10.16+
|
|
Baker Hughes Incorporated Executive Severance Plan (effective
November 1, 2002) (filed as Exhibit 10.13 to Annual Report of
Baker Hughes Incorporated on Form 10-K for the year ended
December 31, 2002). |
|
|
|
10.17+
|
|
Baker Hughes Incorporated Annual Incentive Compensation Plan, as
amended and restated effective January 1, 2005 (filed as Exhibit
10.1 to Quarterly Report of Baker Hughes Incorporated 10-Q for
the quarter ended March 31, 2006). |
|
|
|
10.18+
|
|
Baker Hughes Incorporated Supplemental Retirement Plan, as
amended and restated effective as of January 1, 2005 (filed as
Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on
Form 10-Q for the quarter ended September 30, 2005). |
|
|
|
10.19+*
|
|
First Amendment to Baker Hughes Incorporated Supplemental
Retirement Plan, as amended and restated effective as of January
1, 2005, dated February 9, 2007 to be effective January 1, 2007. |
|
|
|
10.20+
|
|
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). |
|
|
|
10.21+
|
|
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). |
|
|
|
10.22+
|
|
Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan
(filed as Exhibit 4.4 to Registration Statement No. 333-87372 on
Form S-8 filed May 1, 2002). |
92
|
|
|
10.23+
|
|
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). |
|
|
|
10.24+
|
|
Amendment to 2002 Director & Officer Long-Term Incentive Plan,
effective as of October 27, 2005 (filed as Exhibit 10.3 to
Quarterly Report on Form 10-Q for the quarter ended September 30,
2005). |
|
|
|
10.25
|
|
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). |
|
|
|
10.26+
|
|
Baker Hughes Incorporated Pension Plan effective as of January 1,
2002, as amended by First Amendment, effective January 1, 2002
(filed as Exhibit 10.51 to Annual Report of Baker Hughes
Incorporated on Form 10-K for the year ended December 31, 2002). |
|
|
|
10.27+
|
|
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). |
|
|
|
10.28+
|
|
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). |
|
|
|
10.29+
|
|
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). |
|
|
|
10.30
|
|
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). |
|
|
|
10.31
|
|
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). |
|
|
|
10.32+
|
|
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). |
|
|
|
10.33+
|
|
Form of Baker Hughes Incorporated Performance Award Agreement,
including Terms and Conditions for certain executive officers
(filed as Exhibit 10.4 to Quarterly Report of Baker Hughes
Incorporated on Form 10-Q for the quarter ended March 31, 2004). |
|
|
|
10.34+
|
|
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). |
|
|
|
10.35+
|
|
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). |
|
|
|
10.36+
|
|
Form of Baker Hughes Incorporated Restricted Stock Award Terms
and Conditions (filed as Exhibit 10.54 to Annual Report on Form
10-K for the year ended December 31, 2004). |
|
|
|
10.37
|
|
Form of Baker Hughes Incorporated Restricted Stock Unit Agreement
(filed as Exhibit 10.54 to Annual Report on Form 10-K for the
year ended December 31, 2004). |
|
|
|
10.38
|
|
Form of Baker Hughes Incorporated Restricted Stock Unit Terms and
Conditions (filed as Exhibit 10.54 to Annual Report on Form 10-K
for the year ended December 31, 2004). |
|
|
|
10.39+
|
|
Form of Baker Hughes Incorporated Restricted Stock Award,
including Terms and Conditions for directors (filed as Exhibit
10.40 to Annual Report on Form 10-K for the year ended December
31, 2005). |
93
|
|
|
10.40+
|
|
Form of Baker Hughes Incorporated Stock Option Award Agreement,
including Terms and Conditions for directors (filed as Exhibit
10.41 to Annual Report on Form 10-K for the year ended December
31, 2005). |
|
|
|
10.41+*
|
|
Baker Hughes Incorporated Amended and Restated Nonqualified Stock
Option Agreement dated February 24, 2006 between Baker Hughes
Incorporated and Anthony G. Fernandes. |
|
|
|
10.42+
|
|
Form of Baker Hughes Incorporated Performance Unit Award
Agreement, including Terms and Conditions (filed as Exhibit 10.42
to Annual Report on Form 10-K for the year ended December 31,
2005). |
|
|
|
10.43+
|
|
Performance Goals for the Performance Unit Award granted in 2006
(filed as Exhibit 10.43 to Annual Report on Form 10-K for the
year ended December 31, 2005). |
|
|
|
10.44+*
|
|
Form of Performance Goals for the
Performance Unit Awards. |
|
|
|
10.45+*
|
|
Compensation Table for Named Executive Officers and Directors. |
|
|
|
10.46
|
|
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). |
|
|
|
10.47
|
|
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 June 12,
2006). |
|
|
|
10.48
|
|
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). |
|
|
|
10.49
|
|
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). |
|
|
|
10.50+
|
|
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). |
|
|
|
10.51
|
|
Master Formation Agreement by and among the Company, Schlumberger
Limited and certain wholly owned subsidiaries of Schlumberger
Limited dated as of September 6, 2000 (filed as Exhibit 2.1 to
Current Report of Baker Hughes Incorporated on Form 8-K dated
September 7, 2000). |
|
|
|
10.52
|
|
Master Sales Agreement by and among Schlumberger Limited, Baker
Hughes Incorporated and the other parties listed on the signature
pages thereto dated as of April 20, 2006 (filed as Exhibit 2.1 to
Quarterly Report of Baker Hughes Incorporated on Form 10-Q for
the quarter ended March 31, 2006). |
|
|
|
21.1*
|
|
Subsidiaries of Registrant. |
|
|
|
23.1*
|
|
Consent of Deloitte & Touche LLP. |
|
|
|
31.1*
|
|
Certification of Chad C. Deaton, Chief Executive Officer, dated
February 23, 2007, pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934, as amended. |
|
|
|
31.2*
|
|
Certification of Peter A. Ragauss, Chief Financial Officer, dated
February 23, 2007, pursuant to Rule 13a-14(a) of the Securities
Exchange Act of 1934, as amended. |
|
|
|
32*
|
|
Statement of Chad C. Deaton, Chief Executive Officer, and Peter
A. Ragauss, Chief Financial Officer, dated February 23, 2007,
furnished pursuant to Rule 13a-14(b) of the Securities Exchange
Act of 1934, as amended. |
|
|
|
99.1
|
|
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). |
94