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EX-32 - EX-32 - Baker Hughes Holdings LLC | h69014exv32.htm |
EX-31.2 - EX-31.2 - Baker Hughes Holdings LLC | h69014exv31w2.htm |
EX-21.1 - EX-21.1 - Baker Hughes Holdings LLC | h69014exv21w1.htm |
EX-31.1 - EX-31.1 - Baker Hughes Holdings LLC | h69014exv31w1.htm |
EX-23.1 - EX-23.1 - Baker Hughes Holdings LLC | h69014exv23w1.htm |
EX-10.48 - EX-10.48 - Baker Hughes Holdings LLC | h69014exv10w48.htm |
EX-10.33 - EX-10.33 - Baker Hughes Holdings LLC | h69014exv10w33.htm |
EX-10.25 - EX-10.25 - Baker Hughes Holdings LLC | h69014exv10w25.htm |
EX-10.30 - EX-10.30 - Baker Hughes Holdings LLC | h69014exv10w30.htm |
EX-10.41 - EX-10.41 - Baker Hughes Holdings LLC | h69014exv10w41.htm |
EX-10.37 - EX-10.37 - Baker Hughes Holdings LLC | h69014exv10w37.htm |
EX-10.52 - EX-10.52 - Baker Hughes Holdings LLC | h69014exv10w52.htm |
EXCEL - IDEA: XBRL DOCUMENT - Baker Hughes Holdings LLC | Financial_Report.xls |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
OR
o | 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)
Delaware (State or other jurisdiction of incorporation or organization) |
76-0207995 (I.R.S. Employer Identification No.) |
|
2929 Allen Parkway, Suite 2100, Houston, Texas | 77019-2118 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number, including area code: (713) 439-8600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Stock, $1 Par Value per Share | 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 o NO þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or 15(d) of the Exchange Act. YES o NO þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. YES þ NO o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate website, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). 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, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
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, 2009 reported by the New York Stock Exchange) was approximately
$11,257,160,000.
As of February 19, 2010, the registrant has outstanding
311,904,517 shares of common stock, $1
par value per share.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrants Definitive Proxy Statement for the
2010 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
Baker Hughes Incorporated
INDEX
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2 | ||||||||
12 | ||||||||
18 | ||||||||
18 | ||||||||
18 | ||||||||
18 | ||||||||
Part II |
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18 | ||||||||
21 | ||||||||
22 | ||||||||
39 | ||||||||
41 | ||||||||
77 | ||||||||
77 | ||||||||
77 | ||||||||
Part III |
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77 | ||||||||
78 | ||||||||
78 | ||||||||
80 | ||||||||
80 | ||||||||
Part IV |
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80 | ||||||||
EX-10.25 | ||||||||
EX-10.30 | ||||||||
EX-10.33 | ||||||||
EX-10.37 | ||||||||
EX-10.41 | ||||||||
EX-10.48 | ||||||||
EX-10.52 | ||||||||
EX-21.1 | ||||||||
EX-23.1 | ||||||||
EX-31.1 | ||||||||
EX-31.2 | ||||||||
EX-32 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
1
Table of Contents
PART I
ITEM 1. BUSINESS
Baker Hughes Incorporated is a Delaware corporation engaged in the oilfield services industry.
As used herein, Baker Hughes, Company, we, our and us may refer to Baker Hughes
Incorporated and/or its subsidiaries. The use of these terms is not intended to connote any
particular corporate status or relationships. Baker Hughes was formed in April 1987 in connection
with the combination of Baker International Corporation and Hughes Tool Company. We may conduct
our operations through subsidiaries, affiliates, ventures and alliances.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended (the Exchange Act), are made available free of charge
on our Internet website at www.bakerhughes.com as soon as reasonably practicable after these
reports have been electronically filed with, or furnished to, the Securities and Exchange
Commission (the SEC). Information contained on or connected to our website is not incorporated
by reference into this annual report on Form 10-K and should not be considered part of this report
or any other filing we make with the SEC.
We have adopted a Business Code of Conduct to provide guidance to our directors, officers and
employees on matters of business conduct and ethics, including compliance standards and procedures.
We have also required our principal executive officer, principal financial officer and principal
accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct
and Code of Ethical Conduct Certifications are available on the Investor Relations section of our
website at www.bakerhughes.com. We will disclose on a current report on Form 8-K or on our website
information about any amendment or waiver of these codes for our executive officers and directors.
Waiver information disclosed on our website will remain on the website for at least 12 months after
the initial disclosure of a waiver. Our Corporate Governance Guidelines and the charters of our
Audit/Ethics Committee, Compensation Committee, Executive Committee, Finance Committee and
Governance Committee are also available on the Investor Relations section of our website at
www.bakerhughes.com. In addition, a copy of our Business Code of Conduct, Code of Ethical Conduct
Certifications, Corporate Governance Guidelines and the charters of the committees referenced above
are available in print at no cost to any stockholder who requests them by writing or telephoning us
at the following address or telephone number:
Baker Hughes Incorporated
2929 Allen Parkway, Suite 2100
Houston, TX 77019-2118
Attention: Investor Relations
Telephone: (713) 439-8039
2929 Allen Parkway, Suite 2100
Houston, TX 77019-2118
Attention: Investor Relations
Telephone: (713) 439-8039
ABOUT BAKER HUGHES
Baker Hughes is a major supplier of wellbore-related products and technology services and
systems. We operate in over 90 countries around the world and our corporate headquarters is in
Houston, Texas. We provide products and services for drilling and evaluation of oil and gas wells;
completion and production of oil and gas wells; fluids and chemicals used in drilling oil and gas
wells and producing hydrocarbons; and reservoir technology and consulting to the worldwide oil and
natural gas industry. As of December 31, 2009, we had approximately 34,400 employees, of which
approximately 61% work outside the United States.
Prior to May 4, 2009, our business operations were organized primarily through seven product
line divisions and secondarily through four super regions North America; Latin America; Europe,
Africa, Russia, Caspian (EARC); and Middle East, Asia Pacific (MEAP). On May 4, 2009, we
reorganized the Company by geography and product lines. Global operations are now organized into a
number of geomarket organizations, which report into nine region presidents, who in turn report
into two hemisphere presidents. Separately, product-line marketing and technology organizations
report to a president of products and technology. The presidents of the Eastern Hemisphere,
Western Hemisphere, Products and Technology, and the Vice President of Supply Chain report to our
Chief Operating Officer.
The geographic organizations are responsible for sales, field operations and well site
execution. The geographic reorganization of operations is intended to strengthen our
client-focused operations by moving management into the countries where we conduct our business.
Western Hemisphere operations consist of four regions Canada, headquartered in Calgary, Alberta;
U.S. Land and Gulf of Mexico, both headquartered in Houston, Texas; and Latin America,
headquartered in Rio de Janeiro, Brazil. Eastern Hemisphere operations consist of five regions -
Europe, headquartered in London, England; Africa, headquartered in Paris, France; Russia Caspian,
headquartered in Moscow, Russia; Middle East, headquartered in Dubai, United Arab Emirates (UAE);
and Asia Pacific, headquartered in Kuala Lumpur, Malaysia.
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Table of Contents
The product-line marketing and technology organization is responsible for product development,
technology, marketing and delivery of innovative and reliable solutions for our customers to
advance their reservoir performance. The new organization is expected to improve
cross-product-line technology development, sales processes and integrated operations capabilities.
The supply chain organization is responsible for development of cost-effective procurement and
manufacturing of our products and services. We have manufacturing operations in
various countries, including, but not limited to, the United States (Texas, Oklahoma and
Louisiana), the United Kingdom (Scotland and Northern Ireland), Germany (Celle), South America
(Venezuela and Argentina) and the UAE (Dubai).
SEGMENTS
At this time, we continue to review product line financial information as well as geographic
information in deciding how to allocate resources and in assessing performance. Accordingly, we
report our results under two segments: the Drilling and Evaluation segment and the Completion and
Production segment. Collectively, we refer to the results of these two segments as Oilfield
Operations. We have aggregated our product lines within each segment by aligning our product lines
based upon the types of products and services provided to our customers and upon the business
characteristics of the product lines during business cycles. The product lines have similar
economic characteristics and the long-term financial performance of these product lines are
affected by similar economic conditions. They also operate in the same markets, which include all
of the major oil and natural gas producing regions of the world.
| The Drilling and Evaluation segment consists of the following product lines: drilling fluids, drill bits, directional drilling, drilling evaluation services, wireline formation evaluation, wireline completion and production services and reservoir technology and consulting. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells as well as consulting services used in the analysis of oil and gas reservoirs. | ||
| The Completion and Production segment consists of the following product lines: wellbore construction and completion, specialty chemicals, artificial lift systems, permanent monitoring systems, chemical injection systems, integrated operations and project management. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells. |
For additional industry segment information for the three years ended December 31, 2009, see
Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.
Drilling and Evaluation Segment
Our Drilling and Evaluation segment is a leading provider of products and services used in the
drilling and evaluation of oil and natural gas wells. We provide drilling and completion fluids
and fluids environmental services, Tricone® roller cone bits and fixed-cutter polycrystalline
diamond compact (PDC) bits , directional drilling services, measurement-while-drilling (MWD)
and logging-while-drilling (LWD) services, wireline formation evaluation and completion and
production services, and reservoir technology and consulting services.
The primary drivers of our customers buying decisions for drilling and evaluation products
and services include reducing capital expenditures through drilling efficiency (total cost per foot
or meter); reduction of non-productive time; product and service quality and reliability; and
performance which can impact the productivity of the reservoir (wellbore placement and wellbore
quality).
Drilling Fluids
Drilling fluids (also called Mud) are an important component of the drilling process and are
pumped from the surface through the drill string, exiting nozzles in the drill bit and traveling
back up the wellbore where the fluids are recycled. This process cleans the bottom of the well by
transporting the cuttings to the surface while also cooling and lubricating the bit and drill
string. Drilling fluids are typically manufactured by mixing oil, synthetic fluids or water with
barite to give them weight, which enables the fluids to hold the wellbore open and stabilize it.
Additionally, the fluids control downhole pressure and seal porous sections of the wellbore. To
ensure maximum efficiency and wellbore stability, chemical additives are blended by the wellsite
engineer with drilling fluids to achieve particular physical or chemical characteristics. For
drilling through the reservoir itself, drill-in or completion fluids (also called brines) possess
properties that minimize formation damage. Fluids environmental services (also called waste
management) is the process of separating the drill cuttings from the drilling fluids and
re-injecting the processed cuttings into specially prepared wells, or transporting and disposing of
the cuttings by other means.
3
Table of Contents
Drill Bits
We are a leading supplier of tri-cone and diamond drill bits. The primary objective of a
drill bit is to drill a high quality wellbore as efficiently as possible. There are two primary
types of drill bits:
Tricone® Bits. Tricone® drill bits employ either hardened steel teeth or tungsten carbide
insert cutting structures mounted on three rotating cones. These bits work by crushing and
shearing the formation rock as they are turned. Tricone® drill bits have a wide application range.
PDC 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® drill bits.
Advances in PDC technology have expanded the application of PDC bits into harder, more abrasive
formations. A rental market has developed for PDC bits as improvements in bit life and bit repairs
allow a bit to be used to drill multiple wells.
Directional Drilling and Drilling Evaluation Services
We are a leading supplier of drilling and evaluation services, which include directional
drilling, MWD and LWD services.
Directional Drilling. Directional drilling services are used to guide a drill string along a
predetermined path to drill a wellbore to optimally recover hydrocarbons from the reservoir. These
services are used to accurately drill vertical wells, deviated or directional wells (which deviate
from vertical by a planned angle and direction), horizontal wells (which are sections of wells
drilled perpendicular or nearly perpendicular to vertical) and extended reach wells (which are
wells of significant lateral reach or depth). We provide both conventional (using a steerable
motor assembly and mud motor) and rotary based directional drilling systems.
Measurement-While-Drilling. Directional drilling systems need real-time measurements of the
location and orientation of the bottom-hole assembly to operate effectively. MWD systems are
downhole tools that provide this directional information, which is necessary to adjust the drilling
process and guide the wellbore to a specific target. The AutoTrak® rotary steerable system has
these MWD systems built in, allowing the tool to automatically alter its course based on a planned
trajectory.
Logging-While-Drilling. LWD is a variation of MWD in which the LWD tool gathers information
on the petrophysical properties of the formation through which the wellbore is being drilled. Many
LWD measurements are the same as those taken via wireline; however, taking measurements in
real-time before any damage has been sustained by the reservoir as a result of the drilling process
often allows for greater accuracy. Real-time measurements also enable geo-steering where
geological markers identified by LWD tools are used to guide the bit and assure placement of the
wellbore in the optimal location.
Mud Logging Services. We are also a provider of mud logging services, through which our
engineers monitor the interaction between the drilling fluid and the formation and perform
laboratory analysis of drilling fluids and examinations of the drill cuttings to detect the
presence of hydrocarbons and identify the different geological layers penetrated by the drill bit.
Wireline Formation Evaluation and Completion and Production Services
We are a leading provider of wireline formation evaluation and completion and production
services for oil and natural gas wells.
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 provide a direct measure of permeability. At the surface,
measurements are recorded digitally and can be displayed on a continuous graph, or well log,
which shows how each parameter varies along the length of the wellbore. Wireline formation
evaluation tools can also be used to record formation pressures and take samples of formation
fluids to be further evaluated on the surface.
Formation evaluation instrumentation can be run in the well in several ways and at different
times over the life of the well. The two most common methods of data collection are wireline
logging and LWD. Wireline logging is conducted by pulling or pushing instruments through the
wellbore after it is drilled, while LWD instruments are attached to the drill string and take
measurements
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Table of Contents
while the well is being drilled. Wireline logging measurements can be made before the wells
protective steel casing is set (open hole logging) or after casing has been set (cased hole
logging).
We also offer geophysical data interpretation services which help the operator interpret the
petrophysical properties measured by the logging instruments and make inferences about the
formation, presence and quantity of hydrocarbons. This information is used to determine the next
steps in drilling and completing the well.
Wireline Completion and Production Services. Wireline completion and production services
include using wireline instruments to evaluate well integrity, perform mechanical intervention and
perform cement evaluations. Wireline instruments can also be run in producing wells to perform
production logging. We also provide perforating services, which involve puncturing a wells steel
casing and cement sheath with explosive charges. This creates a fracture in the formation and
provides a path for hydrocarbons in the formation to enter the wellbore and be produced.
Reservoir Technology and Consulting
Our reservoir technology and consulting group provides a broad range of services that assist
our customers in the evaluation, drilling, completion and production of oil and gas reservoirs.
Services include well planning, drilling optimization, formation evaluation and imaging, well
placement, sand control completions and stimulation and fracturing operations. We also provide
consulting services to assist customers with operations management, exploration and field
development and reservoir management.
Completion and Production Segment
Our Completion and Production segment provides products and services used in the completion
and production phase of oil and natural gas wells. This includes a wide variety of product lines
which support wellbore construction and completion. This segment also provides specialty chemicals
for the oilfield and refining markets, pipeline inspection and treatment services and the design,
manufacture and repair of artificial lift systems; permanent monitoring and chemical injection
systems; and integrated operations and project management services.
The primary drivers of our customers buying decisions for completion and production products
and services include reducing operating expenditures through improving production rates and
ultimate production; minimizing down time or lost production or the risk of lost production; the
quality and reliability of the equipment; and reducing costs per barrel produced as well as lower
capital expenditures.
Wellbore Construction and Completion
Baker Hughes is a world leader in wellbore construction, cased-hole completions, sand control
and wellbore intervention solutions. The economic success of a well largely depends on how the
well is completed. A successful completion ensures and optimizes the efficient and safe production
of oil and natural gas to the surface. Our completion systems are matched to the formation and
reservoir for optimum production and can employ a variety of products and services.
Wellbore Construction. Wellbore completion products and services include liner hangers,
multilateral completion systems and expandable metal technology. Liner hangers suspend a section
of steel casing (also called a liner) inside the bottom of the previous section of casing. The
liner hangers expandable slips grip the inside of the casing and support the weight of the liner
below. Multilateral completion systems enable two or more zones to be produced from a single well,
using multiple horizontal branches. Expandable metal technology involves the permanent downhole
expansion of a variety of tubular products used in drilling, completion and well remediation
applications.
Cased-Hole Completions. Cased-hole completions products and services include packers, flow
control equipment, subsurface safety valves and intelligent completions. Packers seal the annular
space between the steel production tubing and the casing. These tools control the flow of fluids
in the well and protect the casing above and below from reservoir pressures and corrosive formation
fluids. Flow control equipment controls and adjusts the flow of downhole fluids. A common flow
control device is a sliding sleeve, which can be opened or closed to allow or limit production from
a particular portion of a reservoir. Flow control can be accomplished from the surface via
wireline or downhole via hydraulic or electric motor-based automated systems. Subsurface safety
valves shut off all flow of fluids to the surface in the event of an emergency, thus saving the
well and preventing pollution of the environment. These valves are required in substantially all
offshore wells. Intelligent Completions® use real-time, remotely operated downhole systems to
control the flow of hydrocarbons from one or more zones.
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Table of Contents
Sand Control. Sand control equipment includes gravel pack tools, sand screens and fracturing
fluids. Sand control systems and pumping services are used in loosely consolidated formations to
prevent the production of formation sand with the hydrocarbons.
Wellbore Intervention. Wellbore intervention products and services are designed to protect
producing assets. Intervention operations troubleshoot drilling problems and improve, maintain or
restore economical production from already-producing wells. Products for wellbore intervention
range from service tools and inflatable products to conventional and through-tubing fishing
systems, casing exits, wellbore cleaning and temporary abandonment. 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.
Specialty Chemicals
We are a leading provider of specialty chemicals to the oil and gas industry. We also supply
specialty chemicals to a number of industries including refining, pipeline transportation,
petrochemical, agricultural and iron and steel manufacturing and provide polymer-based products to
a broad range of industrial and consumer markets. Through our Pipeline Management Group, we offer
a variety of products and services for the pipeline transportation industry.
Oilfield Chemicals. We provide oilfield chemical programs for drilling, well stimulation,
production, pipeline transportation and maintenance programs. Our products provide measurable
increases in productivity, decreases in operating and maintenance costs and solutions to
environmental problems. Examples of specialty oilfield chemical programs include emulsion
breakers, corrosion inhibitors, and chemicals which inhibit the formation of paraffin (from organic
material dissolved in crude oil), scale (from mineral-based contaminants dissolved in produced
water), and natural gas hydrates.
Refining, Industrial and Other Specialty Chemicals. For the refining industry, we offer
various process and water treatment programs, as well as finished fuel additives. Examples include
programs to remove salt from crude oil and to control corrosion in processing equipment and
environmentally friendly cleaners that decontaminate refinery equipment and petrochemical vessels
at a lower cost than other methods. We also provide chemical technology solutions to other
industrial markets throughout the world, including petrochemicals, fuel additives, plastics,
imaging, adhesives, steel and crop protection.
Pipeline Management. Baker Hughes offers a variety of products and services for the pipeline
transportation industry. We offer custom turnkey cleaning programs that improve efficiency by
combining chemical treatments with brush and scraper tools that are pumped through the pipeline.
Efficiency can also be improved by adding polymer-based drag reduction agents to reduce the slowing
effects of friction between the pipeline walls and the fluids within, thus increasing throughput
and pipeline capacity. Additional services allow pipelines to operate more safely. These include
inspection and internal corrosion assessment technologies, which physically confirm the structural
integrity of the pipeline. In addition, our flow-modeling capabilities can identify high-risk
segments of a pipeline to ensure proper mitigation programs are in place.
Artificial Lift Systems
We are a leading manufacturer and supplier of artificial lift systems including electrical
submersible pump systems (ESPs) and progressing cavity pump systems (PCPs).
Electrical Submersible Pump Systems. ESPs lift large quantities of oil or oil and water from
wells that do not flow under their own pressure. These artificial lift systems consist of a
centrifugal pump and electric motor installed in the wellbore, armored electric cabling to provide
power to the downhole motor and a variable speed controller at the surface. Baker Hughes designs,
manufactures, markets and installs all the components of ESPs and also offers modeling software to
size ESPs and simulate operating performance. ESPs may be used in both onshore and offshore wells.
The range of appropriate application of ESPs is expanding as technology and reliability
enhancements have improved ESPs performance in harsher environments and marginal reservoirs.
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Progressing Cavity Pump Systems. PCPs are a form of artificial lift comprised of a downhole
progressing cavity pump powered by either a downhole electric motor or a rod turned by a motor on
the surface. PCPs are preferred when the fluid to be lifted is viscous or when the volume is
significantly less than could be economically lifted with ESPs.
Permanent Monitoring and Chemical Injection Systems
Permanent Monitoring Systems. Permanent downhole gauges are used in oil and gas wells to
measure temperature, pressure, flow and other parameters in order to monitor well production as
well as to confirm the integrity of the completion and production equipment in the well. We are a
leading provider of electronic gauges including the engineering, application and field services
necessary to complete an installation of a permanent monitoring system. In addition, we provide
chemical injection line installation and services for treating wells for corrosion, paraffin, scale
and other well performance problems. We also provide fiber optic based permanent downhole gauge
technology for measuring pressure, temperature and distributed temperature. The benefits of fiber
optic sensing include reliability, high temperature properties and the ability to obtain
distributed readings.
Chemical Automation Systems. Chemical automation systems remotely monitor chemical tank
levels that are resident in producing field locations for well treatment or production stimulation
as well as continuously monitor and control chemicals being injected in individual wells. By using
these systems, a producer can ensure proper chemical injection through real-time monitoring and can
also remotely modify the injection parameters to ensure optimized production.
Integrated Operations and Project Management
Integrated Operations and Project Management. We offer integrated operations and project
management services to our customers. Integrated operations and project management is the process
of coordinating the delivery of multiple product lines and services to a specific customer or
project normally under a single contract or agreement, including the coordination of third-party
products and services in addition to those which we may provide. Under a project management
contract, we may be asked to assume responsibility for certain risks related to a project. These
assumed risks may include the performance of our products and services, performance of products and
services of third-party providers, or completion of the project in accordance with specified
technical parameters or in a specified timeframe.
PENDING MERGER WITH BJ SERVICES
On August 30, 2009, the Company and its subsidiary and BJ Services Company (BJ Services)
entered into a merger agreement (the Merger Agreement) pursuant to which the Company will acquire
100% of the outstanding common stock of BJ Services in exchange for newly issued shares of the
Companys common stock and cash. BJ Services is a leading provider of pressure pumping and
oilfield services. The Merger Agreement and the merger have been approved by the Board of
Directors of both the Company and BJ Services. Consummation of the merger is subject to the
approval of the stockholders of the Company and BJ Services stockholders at special meetings
scheduled on March 19, 2010 subject to adjournment or postponement, regulatory approvals, and the
satisfaction or waiver of various other conditions as more fully described in the Merger Agreement.
Subject to receipt of all required approvals, it is anticipated that closing of the merger
will occur in March of 2010. Under the terms of the Merger Agreement, each share of BJ
Services common stock will be converted into the right to receive 0.40035 shares of the Companys
common stock and $2.69 in cash. Baker Hughes has estimated the total consideration expected to be
issued and paid in the merger to be approximately $6.4 billion, consisting of approximately $0.8
billion to be paid in cash and approximately $5.6 billion to be paid through the issuance of
approximately 118 million shares of Baker Hughes common stock valued at the February 11, 2010
closing share price of $46.68 per share. The value of the merger consideration will fluctuate
based upon changes in the price of shares of Baker Hughes common stock and the number of BJ
Services common shares and options outstanding at the closing date.
MARKETING, COMPETITION AND ECONOMIC CONDITIONS
We market our products and services on a product line basis primarily through our own sales
organizations, although certain of our products and services are marketed through independent
distributors, commercial agents, licensees or sales representatives. Over the past several years,
we have significantly reduced the number of commercial agents that we use to conduct our business.
In the markets in which we formerly utilized commercial agents, we have established our own
marketing operations and are continuing to build direct relationships with our customers. We
ordinarily provide technical and advisory services to assist in our customers use of our products
and services. Stock points and service centers for our products and services are located in areas
of drilling and production activity throughout the world.
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Our primary competitors include the major diversified oil service companies such as
Schlumberger, Halliburton and Weatherford, where the breadth of service capabilities as well as
competitive position of each product line are the keys to differentiation in the
market. We also compete with other competitors who may participate in only a few product
lines, for example, Smith International, National Oilwell Varco, Champion Technologies, Inc., Nalco
Holding Company, and Newpark Resources, Inc.
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 believe that the principal competitive factors in
our industries are product and service quality, availability and reliability, health, safety and
environmental standards, technical proficiency and price.
Further information is set forth in Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations and Note 13 of the Notes to Consolidated Financial
Statements in Item 8 herein.
INTERNATIONAL OPERATIONS
We operate in over 90 countries around the world. We have manufacturing operations
internationally in various countries including, but not limited, to the United Kingdom, Germany,
Venezuela, Argentina, and the UAE. The business operations of our two segments are organized
around nine primary geographic regions. In the Western Hemisphere there are four regions: U.S.
Land, Gulf of Mexico, Canada and Latin America. In the Eastern Hemisphere there are five regions:
Europe, Africa, Russia Caspian, Middle East, and Asia Pacific. Through this structure, we have
placed our management close to our customers, facilitating stronger customer relationships and
allowing us to react more quickly to local market conditions and needs.
Our operations are subject to the risks inherent in doing business in multiple countries with
various laws and differing political environments. These risks include the risks identified in
Item 1A. Risk Factors. Although it is impossible to predict the likelihood of such occurrences
or their effect on us, we routinely evaluate these risks and take appropriate actions to mitigate
the risks where possible. However, there can be no assurance that an occurrence of any one or more
of these events would not have a material adverse effect on our operations.
Further information is set forth in Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations.
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, 2009, see Note 1 of the Notes to Consolidated Financial Statements in Item 8
herein.
We have followed a policy of seeking patent and trademark protection in numerous countries and
regions through out the world 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. No single
patent or trademark is considered to be critical to our business.
SEASONALITY
Our operations can be affected by seasonal weather, which can temporarily affect the delivery
and performance of our products and services, as well as customers budgetary cycles for capital
expenditures. The widespread geographic locations of our operations and the timing of seasonal
events serve to reduce the impact of individual events. Examples of seasonal events which can
impact our business include:
| the severity and duration of the winter in North America can have a significant impact on gas storage levels and drilling activity for natural gas; | ||
| the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions; | ||
| hurricanes can disrupt coastal and offshore drilling and production operations; |
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| severe weather during the winter months normally results in reduced activity levels in the North Sea and Russia; and | ||
| large export orders which tend to be sold in the second half of a calendar year. |
RAW MATERIALS
We purchase various raw materials and component parts for use in manufacturing our products.
The principal materials we purchase are steel alloys (including chromium and nickel), titanium,
beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds, printed circuit boards
and other electronic components and hydrocarbon-based chemical feed stocks. These materials are
generally available from multiple sources and may be subject to price volatility. We have not
experienced significant shortages of these materials and normally do not carry inventories of such
materials in excess of those reasonably required to meet our production schedules. We do not
expect significant interruptions in supply, but there can be no assurance that there will be no
price or supply issues over the long term.
EMPLOYEES
On December 31, 2009, we had approximately 34,400 employees, as compared with approximately
39,800 employees on December 31, 2008. Approximately 2,900 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.
EXECUTIVE OFFICERS
The following table shows, as of February 25, 2010, the name of each of our executive
officers, together with his age and all offices presently held.
Name | Age | |||||
Chad C. Deaton
|
57 | Chairman of the Board, President and Chief Executive Officer of the Company since February 2008. Chairman of the Board and Chief Executive Officer from 2004 to 2008. President and Chief Executive Officer of Hanover Compressor Company from 2002 to 2004. Senior Advisor to Schlumberger Oilfield Services from 1999 to 2001. Executive Vice President of Schlumberger from 1998 to 1999. Employed by the Company in 2004. | ||||
Peter A. Ragauss
|
52 | Senior Vice President and Chief Financial Officer of the Company since 2006. Segment Controller of Refining and Marketing for BP plc from 2003 to 2006. Mr. Ragauss joined BP plc in 1998 as Assistant to the Group Chief Executive until 2000 when he became Chief Executive Officer of Air BP. Vice President of Finance and Portfolio Management for Amoco Energy International immediately prior to its merger with BP in 1998. Vice President of Finance for El Paso Energy International from 1996 to 1998 and Vice President of Corporate Development for Tenneco Energy in 1996. Employed by the Company in 2006. | ||||
Alan R. Crain
|
58 | Senior Vice President and General Counsel of the Company since 2007. Vice President and General Counsel from 2000 to 2007. Executive Vice President, General Counsel and Secretary of Crown, Cork & Seal Company, Inc. from 1999 to 2000. Vice President and General Counsel from 1996 to 1999, and Assistant General Counsel from 1988 to 1996, of Union Texas Petroleum Holdings, Inc. Employed by the Company in 2000. | ||||
Martin S. Craighead
|
50 | Senior Vice President and Chief Operating Officer effective April 30, 2009. Group President of Drilling and Evaluation since 2007 and Vice President of the Company from 2005 until April 30, 2009. President of INTEQ from 2005 to 2007. President of Baker Atlas from February 2005 to August 2005. Vice President of Worldwide Operations for Baker Atlas from 2003 to 2005 and Vice President, Marketing and Business Development for Baker Atlas from 2001 to 2003; Region Manager for Baker Atlas in Latin America and Asia and Region Manager for E&P Solutions from 1995 to 2001. Employed by the Company in 1986. |
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Name | Age | |||||
Russell J. Cancilla
|
58 | Vice President, and Chief Security Officer, Health, Safety, Environment and Security of the Company since 2009. Chief Security Officer from June 2006 to January 2009. Vice President and Security Officer of Innovene from 2005 to 2006; Vice President, Resources & Capabilities for HSSE for BP from 2003 to 2005 and Vice President, Real Estate and Management Services for BP from 1998 to 2003. Employed by the Company in 2006. | ||||
Belgacem Chariag
|
47 | Vice President of the Company and President Eastern Hemisphere Operations since 2009. Vice President/Director HSE of Schlumberger Limited from May 2008 to May 2009. President of Well Services, a Schlumberger product line, from 2006 to 2008. Vice President Strategic Marketing Oilfield Services for Europe, Africa and CIS of Schlumberger from 2004 to 2006. Various other positions at Schlumberger from 1989 to 2008. Employed by the Company in 2009. | ||||
Didier Charreton
|
46 | Vice President, Human Resources of the Company since 2007. Group Human Resources Director of Coats Plc, a global company engaged in the sewing thread and needlecrafts industry, from 2002 to 2007. Business Development of ID Applications for Gemplus S.A., a global company in the Smart Card industry, from 2000 to 2001. Various human resources positions at Schlumberger from 1989 to 2000. Employed by the Company in 2007. | ||||
Alan J. Keifer
|
55 | Vice President and Controller of the Company since 1999. Western Hemisphere Controller of Baker Oil Tools from 1997 to 1999 and Director of Corporate Audit for the Company from 1990 to 1996. Employed by the Company in 1990. | ||||
Jay G. Martin
|
58 | Vice President, Chief Compliance Officer and Senior Deputy General Counsel of the Company since 2004. Shareholder at Winstead Sechrest & Minick P.C. from 2001 to 2004. Partner, Phelps Dunbar from 2000 to 2001 and Partner, Andrews & Kurth from 1996 to 2000. Employed by the Company in 2004. | ||||
Derek Mathieson
|
39 | Vice President of the Company since December 2008. President, Products and Technology since May 2009. Chief Technology and Marketing Officer of the Company from December 2008 to May 2009. Chief Executive Officer of WellDynamics, Inc. from May 2007 to November 2008. Vice President Business Development, Technology and Marketing of WellDynamics, Inc. from April 2006 to May 2007; Technology Director and Chief Technology Officer from January 2004 to April 2006; Research and Development Manager from August 2002 to January 2004 and Reliability Assurance Engineer from April 2001 to August 2002 of WellDynamics, Inc. Well Engineer, Shell U.K. Exploration and Production 1997 to 2001. Employed by the Company in 2008. | ||||
John A. ODonnell
|
61 | Vice President of the Company since 1998 and President Western Hemisphere Operations since May 2009. President of Baker Petrolite Corporation from 2005 to May 2009. 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. | ||||
Arthur L. Soucy
|
47 | Vice President Supply Chain of the Company since April 2009. Vice President, Global Supply Chain for Pratt and Whitney from 2007 to 2009. Sloan Fellows Program, Innovation and Global Leadership at Massachusetts Institute of Technology from 2006 to 2007. General Manager, Combustors, Augmenters and Nozzles of Pratt and Whitney from 2005 to 2006. Various managerial positions at Pratt and Whitney from 1995 to 2006. Employed by the Company in 2009. | ||||
Clifton N.B. Triplett
|
51 | Vice President and Chief Information Officer of the Company since September 2008. Corporate Vice President, Motorola Global Services from 2007 to 2008 and Corporate Vice President and Chief Information Officer of Motorolas Network and Enterprise Group from 2006 to 2007. Employed by General Motors from 1997 to 2006 as Global Information Systems Officer for Computing and Telecommunications Services from 2003 to 2006 and Global Manufacturing and Quality Information Systems Officer from 1997 to 2003. Employed by the Company in 2008. |
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There are no family relationships among our executive officers.
ENVIRONMENTAL MATTERS
We are committed to the health and safety of people, protection of the environment and
compliance with laws, regulations and our policies. Our past and present operations include
activities that are subject to domestic (including U.S. federal, state and local) and international
regulations with regard to air and water quality and other environmental matters. We believe we
are in substantial compliance with these regulations. Regulation in this area continues to evolve,
and changes in standards of enforcement of existing regulations, as well as the enactment and
enforcement of new legislation, may require us and our customers to modify, supplement or replace
equipment or facilities or to change or discontinue present methods of operation.
We are involved in voluntary remediation projects at some of our present and former
manufacturing locations or other facilities, the majority of which relate to properties obtained in
acquisitions or to sites no longer actively used in operations. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order.
Estimated remediation costs are accrued using currently available facts, existing environmental
permits, technology and presently enacted laws and regulations. For sites where we are primarily
responsible for the remediation, our cost estimates are developed based on internal evaluations and
are not discounted. We record accruals when it is probable that we will be obligated to pay
amounts for environmental site evaluation, remediation or related activities, and such amounts can
be reasonably estimated. If the obligation can only be estimated within a range, we accrue the
minimum amount in the range. In general, we seek to accrue costs for the most likely scenario,
where known. Accruals are recorded even if significant uncertainties exist over the ultimate cost
of the remediation. Ongoing environmental compliance costs, such as obtaining environmental
permits, installation of pollution control equipment and waste disposal, are expensed as incurred.
The Comprehensive Environmental Response, Compensation and Liability Act (known as Superfund
or CERCLA) imposes liability for the release of a hazardous substance into the environment.
Superfund liability is imposed without regard to fault, even if the waste disposal was in
compliance with laws and regulations. The United States Environmental Protection Agency (the
EPA) and appropriate state agencies supervise investigative and cleanup activities at Superfund
sites.
We have been identified as a potentially responsible party (PRP) in remedial activities
related to various Superfund sites, and we accrue our share of the estimated remediation costs of
the site based on the ratio of the estimated volume of waste we contributed to the site to the
total volume of waste disposed at the site. PRPs in Superfund actions have joint and several
liability for all costs of remediation. Accordingly, a PRP may be required to pay more than its
proportional share of such costs. For some projects, it is not possible at this time to quantify
our ultimate exposure because the projects are either in the investigative or early remediation
stage, or allocation information is not yet available. However, based upon current information, we
do not believe that probable or reasonably possible expenditures in connection with the sites are
likely to have a material adverse effect on our consolidated financial statements because we have
recorded adequate reserves to cover the estimate we presently believe will be our ultimate
liability in the matter. Further, other PRPs involved in the sites have substantial assets and may
reasonably be expected to pay their share of the cost of remediation, and, in some circumstances,
we have insurance coverage or contractual indemnities from third parties to cover a portion of or
the ultimate liability.
During the year ended December 31, 2009, we spent $35 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 2010, we
expect to spend approximately $43 million to comply with Environmental Regulations. During the
year ended December 31, 2009, we incurred $22 million in capital expenditures for environmental
control equipment, and we estimate we will incur approximately $24 million during 2010. Based upon
current information, we believe that our compliance with Environmental Regulations will not have a
material adverse effect upon our capital expenditures, earnings or competitive position because we
have either established adequate reserves or our cost for that compliance is not expected to be
material to our consolidated financial statements. Our total accrual for environmental remediation
is $18 million and $17 million, which includes accruals of $6 million and $6 million for the
various Superfund sites, at December 31, 2009 and 2008, respectively.
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.
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ITEM 1A. RISK FACTORS
An investment in our common stock involves various risks. When considering an investment in
our Company, one should consider carefully all of the risk factors described below, as well as
other information included and incorporated by reference in this report. There may be additional
risks, uncertainties and matters not listed below, that we are unaware of, or that we currently
consider immaterial. Any of these could adversely affect our business, financial condition,
results of operations and cash flows and, thus, the value of an investment in our Company.
Risk Factors Related to the Worldwide Oil and Natural Gas Industry
Our business is focused on providing products and services to the worldwide oil and natural
gas industry; therefore, our risk factors include those factors that impact, either positively or
negatively, the markets for oil and natural gas. Expenditures by our customers for exploration,
development and production of oil and natural gas are based on their expectations of future
hydrocarbon demand, the risks associated with developing the reserves, their ability to finance
exploration for and development of reserves, and the future value of the reserves. Their
evaluation of the future value is based, in part, on their expectations for global demand, global
supply, excess production capacity, inventory levels, and other factors that influence oil and
natural gas prices. The key risk factors currently influencing the worldwide oil and natural gas
markets are discussed below.
Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect
our operating results. Changes in the global economy or credit market could impact our customers
spending levels and our revenues and operating results.
Demand for oil and natural gas, as well as the demand for our services, is highly correlated
with global economic growth, and in particular by the economic growth of countries such as the
U.S., India, and China, as well as developing countries in Asia and the Middle East who are either
significant users of oil and natural gas or whose economies are experiencing the most rapid
economic growth compared to the global average. The past slowdown in global economic growth and
recession in the developed economies resulted in reduced demand for oil and natural gas, increased
spare productive capacity and lower energy prices. Weakness or deterioration of the global economy
or credit market could reduce our customers spending levels and reduce our revenues and operating
results. Incremental weakness in global economic activity, particularly in China, India, the
Middle East and developing Asia will reduce demand for oil and natural gas and result in lower oil
and natural gas prices. Incremental strength in global economic activity in such areas will create
more demand for oil and natural gas and support higher oil and natural gas prices. In addition,
demand for oil and natural gas could be impacted by environmental
regulation, including cap and trade legislation, carbon taxes
and the cost for carbon capture and sequestration
related regulations.
Volatility of oil and natural gas prices can adversely affect demand for our products and services.
Volatility in oil and natural gas prices can also impact our customers activity levels and
spending for our products and services. Current energy prices are important contributors to cash
flow for our customers and their ability to fund exploration and development activities.
Expectations about future prices and price volatility are important for determining future spending
levels.
Lower oil and gas prices generally lead to decreased spending by our customers. While higher
oil and natural gas prices generally lead to increased spending by our customers, sustained high
energy prices can be an impediment to economic growth, and can therefore negatively impact spending
by our customers. Our customers also take into account the volatility of energy prices and other
risk factors by requiring higher returns for individual projects if there is higher perceived risk.
Any of these factors could affect the demand for oil and natural gas and could have a material
adverse effect on our results of operations.
Many of our customers activity levels and spending for our products and services and ability to
pay amounts owed us have been impacted by economic conditions.
Access to capital is dependent on our customers ability to access the funds necessary to
develop economically attractive projects based upon their expectations of future energy prices,
required investments and resulting returns. Limited access to external sources of funding has
caused many customers to reduce their capital spending plans to levels supported by
internally-generated cash flow. In addition, the combination of a reduction of cash flow resulting
from declines in commodity prices, a reduction in borrowing bases under reserve-based credit
facilities and the lack of availability of debt or equity financing may impact the ability of our
customers to pay amounts owed to us. Starting in late 2008 and continuing through the fourth
quarter of 2009, we experienced a delay in receiving payments from our customers in Venezuela.
As of December 31, 2009, our accounts receivable in Venezuela totaled approximately 5% of our
total accounts receivable. For the year ended December 31, 2009, Venezuela revenues were
approximately 2% of our total consolidated revenues.
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Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect
our operating results.
Productive capacity for oil and natural gas is dependent on our customers decisions to
develop and produce oil and natural gas reserves. The ability to produce oil and natural gas can
be affected by the number and productivity of new wells drilled and completed, as well as the rate
of production and resulting depletion of existing wells. Advanced technologies, such as horizontal
drilling, improve total recovery but also result in a more rapid production decline.
Access to prospects is also important to our customers. Access to prospects may be limited
because host governments do not allow access to the reserves or because another oil and natural gas
exploration company owns the rights to develop the prospect. Government regulations and the costs
incurred by oil and natural gas exploration companies to conform to and comply with government
regulations, may also limit the quantity of oil and natural gas that may be economically produced.
Supply can also be impacted by the degree to which individual Organization of Petroleum
Exporting Countries (OPEC) nations and other large oil and natural gas producing countries,
including, but not limited to, Norway and Russia, are willing and able to control production and
exports of oil, to decrease or increase supply and to support their targeted oil price while
meeting their market share objectives. Any of these factors could affect the supply of oil and
natural gas and could have a material adverse effect on our results of operations.
Changes in spare productive capacity or inventory levels can be indicative of future customer
spending to explore for and develop oil and natural gas which in turn influences the demand for our
products and services.
Spare productive capacity and oil and natural gas storage inventory levels are an indicator of
the relative balance between supply and demand. High or increasing storage or inventories
generally indicate that supply is exceeding demand and that energy prices are likely to soften.
Low or decreasing storage or inventories are an indicator that demand is growing faster than supply
and that energy prices are likely to rise. Measures of maximum productive capacity compared to
demand (spare productive capacity) are also an important factor influencing energy prices and
spending by oil and natural gas exploration companies. When spare productive capacity is low
compared to demand, energy prices tend to be higher and more volatile reflecting the increased
vulnerability of the entire system to disruption.
Seasonal and adverse weather conditions adversely affect demand for our services and operations.
Weather can also have a significant impact on demand as consumption of energy is seasonal, and
any variation from normal weather patterns, cooler or warmer summers and winters, can have a
significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of
Mexico, may interrupt or curtail our operations, or our customers operations, cause supply
disruptions and result in a loss of revenue and damage to our equipment and facilities, which may
or may not be insured. Extreme winter conditions in Canada, Russia or the North Sea may interrupt
or curtail our operations, or our customers operations, in those areas and result in a loss of
revenue.
Risk Factors Related to Our Business
Our expectations regarding our business are affected by the following risk factors and the
timing of any of these risk factors:
We operate in a highly competitive environment, which may adversely affect our ability to succeed.
We operate in a highly competitive environment for marketing oilfield services and securing
equipment and trained personnel. Our ability to continually provide competitive products and
services can impact our ability to defend, maintain or increase prices for our products and
services, maintain market share and negotiate acceptable contract terms with our customers. In
order to be competitive, we must provide new technologies and reliable products and services that
perform as expected and that create value for our customers. Our ability to defend, maintain or
increase prices for our products and services is in part dependent on the industrys capacity
relative to customer demand, and on our ability to differentiate the value delivered by our
products and services from our competitors products and services. In addition, our ability to
negotiate acceptable contract terms and conditions with our customers, especially state-owned
national oil companies, our ability to manage warranty claims and our ability to effectively manage
our commercial agents can also impact our results of operations.
Managing development of competitive technology and new product introductions on a forecasted
schedule and at forecasted costs can impact our financial results. Development of competing
technology that accelerates the obsolescence of any of our products or services can have a
detrimental impact on our financial results and can result in the potential impairment of
long-lived assets.
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We may be disadvantaged competitively and financially by a significant movement of exploration
and production operations to areas of the world in which we are not currently active.
The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel,
particularly in periods of rapid growth, could adversely affect our ability to execute our
operations on a timely basis.
Our manufacturing operations are dependent on having sufficient raw materials, component parts
and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while
minimizing inventories. Our ability to effectively manage our manufacturing operations and meet
these goals can have an impact on our business, including our ability to meet our manufacturing
plans and revenue goals, control costs and avoid shortages of raw materials and component parts.
Raw materials and components of particular concern include steel alloys (including chromium and
nickel), titanium, beryllium, copper, lead, tungsten carbide, synthetic and natural diamonds,
electronic components and hydrocarbon-based chemical feed stocks. Our ability to repair or replace
equipment damaged or lost in the well can also impact our ability to service our customers. A lack
of manufacturing capacity could result in increased backlog, which may limit our ability to respond
to short lead time orders.
People are a key resource to developing, manufacturing and delivering our products and
services to our customers around the world. Our ability to manage the recruiting, training and
retention of the highly skilled workforce required by our plans and to manage the associated costs
could impact our business. A well-trained, motivated work force has a positive impact on our
ability to attract and retain business. Periods of rapid growth present a challenge to us and our
industry to recruit, train and retain our employees while managing the impact of wage inflation and
potential lack of available qualified labor in the markets where we operate. Likewise, in the
current condition of the economy and our markets, we may have to adjust our workforce to control
costs and yet not lose our skilled and diverse workforce. Labor-related actions, including
strikes, slowdowns and facility occupations can also have a negative impact on our business.
Our business is subject to geopolitical and terrorism risks.
Geopolitical risks and terrorist activity continue to grow in several key countries where we
do business. Geopolitical risks could lead to, among other things, a loss of our investment in the
country and an inability to collect our accounts receivable. Terrorism risks could lead to a loss
of our investment in the country, as well as a disruption in business activities. Key oil
producing countries in which we do business include Angola, Brazil, Canada, China, Norway, Russia,
Saudi Arabia, U.K., U.S. and Venezuela.
The terms and the impact of the settlement with the Department of Justice (DOJ) and SEC may
negatively impact our ongoing operations.
Under the settlements in connection with the previously disclosed compliance investigations by
the DOJ and SEC, we are subject to ongoing review and regulation of our business operations,
including the review of our operations and compliance program by an independent monitor appointed
to assess our Foreign Corrupt Practices Act (FCPA) policies and procedures. The activities of
the independent monitor will have a cost to us and may cause a change in our processes and
operations, the outcome of which we are unable to predict. In addition, the settlements may impact
our operations or result in legal actions against us in the countries that are the subject of the
settlements. Also, the collateral impact of settlement in the United States and other countries
outside the United States where we do business that may claim jurisdiction over any of the matters
related to the DOJ and SEC settlements could be material. These settlements could also result in
third-party claims against us, which may include claims for special, indirect, derivative or
consequential damages.
Our failure to comply with the terms of our agreements with the DOJ and SEC would have a negative
impact on our ongoing operations.
The settlements reached with the DOJ and SEC could be substantially nullified and we could be
subject to severe sanctions and civil and criminal prosecution as well as fines and penalties in
the event of a subsequent violation by us or any of our employees or our failure to meet all of the
conditions contained in the settlements. The impact of the settlements on our ongoing operations
could include limits on revenue growth and increases in operating costs. Our ability to comply
with the terms of the settlements is dependent on the success of our ongoing compliance program,
including our ability to continue to manage our agents and business partners and supervise, train
and retain competent employees and the efforts of our employees to comply with applicable law and
the Baker Hughes Business Code of Conduct.
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Compliance with and changes in laws or adverse positions taken by taxing authorities could be
costly and could affect operating results.
We have operations in the U.S. and in over 90 countries that can be impacted by expected and
unexpected changes in the legal and business environments in which we operate. Our ability to
manage our compliance costs will impact our ability to meet our earnings goals. Compliance related
issues could also limit our ability to do business in certain countries. Changes that could impact
the legal environment include new legislation, new regulations, new policies, investigations and
legal proceedings and new interpretations of existing legal rules and regulations, in particular,
changes in export control laws or exchange control laws, additional restrictions on doing business
in countries subject to sanctions, and changes in laws in countries where we operate or intend to
operate. Changes that impact the business environment include changes in accounting standards,
changes in environmental laws, changes in tax laws or tax rates, the resolution of tax assessments
or audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards
and tax credits. In addition, we may periodically restructure our legal entity organization. If
taxing authorities were to disagree with our tax positions in connection with any such
restructurings, our effective tax rate could be materially impacted.
These changes could have a significant financial impact on our future operations and the way
we conduct, or if we conduct, business in the affected countries.
Uninsured claims and litigation could adversely impact our operating results.
We could be impacted by the outcome of pending litigation as well as unexpected litigation or
proceedings. We have insurance coverage against operating hazards, including product liability
claims and personal injury claims related to our products, to the extent deemed prudent by our
management and to the extent insurance is available, however, no assurance can be given that the
nature and amount of that insurance will be sufficient to fully indemnify us against liabilities
arising out of pending and future claims and litigation. This insurance has deductibles or
self-insured retentions and contains certain coverage exclusions. The insurance does not cover
damages from breach of contract by us or based on alleged fraud or deceptive trade practices.
Whenever possible, we obtain agreements from customers that limit our liability. Insurance and
customer agreements do not provide complete protection against losses and risks, and our results of
operations could be adversely affected by unexpected claims not covered by insurance.
Compliance with and rulings and litigation in connection with environmental regulations may
adversely affect our business and operating results.
Our business is impacted by unexpected outcomes or material changes in environmental
liability. Our expectations regarding our compliance with environmental regulations and our
expenditures to comply with environmental regulations, including (without limitation) our capital
expenditures for environmental control equipment, are only our forecasts regarding these matters.
These forecasts may be substantially different from actual results, which may be affected by the
following factors: changes in environmental regulations; a material change in our allocation or
other unexpected, adverse outcomes with respect to sites where we have been named as a PRP,
including (without limitation) Superfund sites; the discovery of new sites of which we are not
aware and where additional expenditures may be required to comply with environmental regulations;
an unexpected discharge of hazardous materials.
A variety of regulatory developments, proposals or requirements have been introduced in the
U.S. and various other countries that are focused on restricting the emission of carbon dioxide,
methane and other gases. Among these developments are the United Nations Framework
Convention on Climate Change, also known as the Kyoto Protocol (an internationally applied
protocol, which has been ratified in Canada, the Regional Greenhouse Gas Initiative or RGGI in
the Northeastern United States, and the Western Regional Climate Action Initiative in the Western
United States). Also, in 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that
certain gases are an air pollutant under the federal Clean Air Act and thus subject to future
regulation. These developments may curtail production and demand for fossil fuels such as oil and
gas in areas of the world where customers of the company operate and thus adversely affect
future demand for products and services of the company, which may in turn adversely affect
future results of operations.
Control of oil and gas reserves by state-owned oil companies may impact the demand for our services
and create additional risks in our operations.
Much of the worlds oil and gas reserves are controlled by state-owned oil companies.
State-owned oil companies may require their contractors to meet local content requirements or other
local standards, such as joint ventures, that could be difficult or undesirable for the Company to
meet. The failure to meet the local content requirements and other local standards may adversely
impact the Companys operations in those countries.
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In addition, many state-owned oil companies may require integrated contracts or turn-key
contracts that could require the Company to provide services outside its core business. Providing
services on an integrated or turnkey basis generally requires the Company to assume additional
risks.
Changes in economic conditions and currency fluctuations may impact our operating results.
Fluctuations in foreign currencies relative to the U.S. Dollar can impact our revenue and our
costs of doing business. Most of our products and services are sold through contracts denominated
in U.S. Dollars or local currency indexed to U.S. Dollars. Some revenue and some local expenses
and some of our manufacturing costs are incurred in local currencies and therefore changes in the
exchange rates between the U.S. Dollar and foreign currencies, particularly the British Pound
Sterling, Euro, Canadian Dollar, Norwegian Krone, Russian Ruble, Australian Dollar, Brazilian Real
and the Venezuelan Bolivar (which was devalued by the Venezuelan government in January 2010), can
increase or decrease our revenue and expenses reported in U.S. Dollars and may impact our results
of operations.
The condition of the capital markets and equity markets in general can affect the price of our
common stock and our ability to obtain financing, if necessary. If the Companys credit rating is
downgraded, this would increase borrowing costs under our revolving credit agreements and
commercial paper program, as well as the cost of renewing or obtaining, or make it more difficult
to renew or obtain or issue, new debt financing.
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.
Risk Factors Related to the Merger with BJ Services
Our expectations regarding our business may be impacted by the following risk factors related
to the pending merger with BJ Services:
Failure to complete the merger with BJ Services could negatively affect our stock price and our
future business and financial results.
Completion of the merger with BJ Services is not assured and is subject to risks, including
the risks that approval of the transaction by stockholders of both Baker Hughes and BJ Services is not obtained or
that certain other closing conditions are not satisfied. If the merger is not completed, our
ongoing business may be adversely affected and will be subject to several risks, including the
following:
| having to pay certain significant costs relating to the merger without receiving the benefits of the merger, including in certain circumstances a termination fee of $175 million to BJ Services; | ||
| the attention of our management will have been diverted to the merger instead of on our operations and pursuit of other opportunities that may have been beneficial to us; and | ||
| resulting negative customer perception could adversely affect our ability to compete for, or to win, new and renewal business in the marketplace. |
We will incur substantial transaction and merger-related costs as well as assume additional debt
from BJ Services in connection with the merger and our stockholders will be diluted by the merger.
We expect to incur a number of non-recurring transaction and merger-related costs associated
with completing the merger with BJ Services, combining the operations of the two companies and
achieving desired synergies. These fees and costs will be substantial. Additional unanticipated
costs may be incurred in the integration of the businesses of Baker Hughes and BJ Services.
Although we expect that the elimination of certain duplicative costs, as well as the realization of
other efficiencies related to the integration of the two businesses, will offset the incremental
transaction and merger-related costs over time, this net benefit may not be achieved in the near
term, or at all. In addition, we will assume approximately $500 million of long-term debt from BJ
Services.
The merger will dilute the ownership position of our current stockholders who are expected to
hold approximately 72.5% of the combined companys common stock on a fully diluted basis
immediately after the merger.
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If the merger is completed, we will be subject to additional risks.
The success of the merger will depend, in part, on our ability to realize these anticipated
benefits from combining the businesses of Baker Hughes and BJ Services. However, to realize these
anticipated benefits, we must successfully integrate the operations and personnel of BJ Services
into our business. If we are not able to achieve these objectives, the anticipated benefits of the
merger may not be realized fully or at all or may take longer to realize than expected. Because we
and BJ Services have operated independently and, until the completion of the merger, we will
continue to operate independently, it is possible that the integration process could take longer
than anticipated and could result in the loss of valuable employees or the disruption of each
companys ongoing businesses or inconsistencies in standards, controls, procedures, practices,
policies and compensation arrangements, which could adversely affect the combined companys ability
to achieve the anticipated benefits of the merger. The combined companys results of operations
could also be adversely affected by any issues attributable to either companys operations that
arise or are based on events or actions that occur prior to the closing of the merger. Further,
the size of the merger may make integration difficult, expensive and disruptive, adversely
affecting our revenues after the merger. Failure to achieve the anticipated benefits could result
in increased costs or decreases in the amount of expected revenues and could adversely affect our
future business, financial condition, operating results and prospects. In addition, we may not be
able to eliminate duplicative costs or realize other efficiencies from integrating the businesses
to offset part or all of the transaction and merger-related costs incurred by us.
Our performance following the merger, could be adversely affected if we are unable to retain
and maintain high technology equipment and certain key employees and to a greater extent by the
skilled labor shortages of certain types of qualified personnel, including engineers, project
managers, field supervisors, linemen and other qualified personnel, which both Baker Hughes and BJ
Services have from time-to-time experienced. These shortages have also negatively impacted, and
may continue to negatively impact, the productivity and profitability of certain projects and can
result in lost sales during periods of unanticipated demand. Our inability to bid on new and
attractive projects, or maintain productivity and profitability on existing projects, including
ones developed by BJ Services, due to the limited supply of high technology equipment and skilled
workers could negatively affect our profitability and results of operation.
In addition, the approval or regulatory requirements of certain government or regulatory
agencies in connection with the merger could contain terms, conditions, or restrictions, such as
the divestiture of assets or line of business that would be detrimental to the Company after the
merger. Additionally, even after the statutory waiting period under the anti-trust laws and even
after completion of the merger, governmental authorities could seek to block or challenge the
merger as they deem necessary or desirable in the public interest. In addition, in some
jurisdictions, a competitor, customer or other third party could initiate a private action under
the antitrust laws challenging or seeking to enjoin the merger, before or after it is completed.
The Company or BJ Services may not prevail and may incur significant costs in defending or settling
any action under the anti-trust laws.
Upon consummation of the merger, a portion of the combined companys revenues will be derived from its North
American operations. Because of the economic environment and related decrease in demand for energy, natural
gas exploration and production in North America have decreased significantly from their peak levels
in the summer of 2008. Many factors may adversely impact demand for natural gas and, therefore,
demand for oilfield services. Further decline in natural gas exploration and production could
cause a decline in the demand for the services and products of the combined company. Such decline
could result in a significant adverse effect on our operating results and the expected benefits of
the merger.
In addition to disclosures in this annual report regarding the Companys settlements, as
further described in its SEC filings, BJ Services has voluntarily disclosed information found in its
internal investigations to the DOJ and SEC and has engaged in discussions with these authorities in
connection with their review of possible illegal payments. Neither BJ Services nor the Company can
currently predict the outcome of its investigations, when any of these matters will be resolved, or
what, if any, actions may be taken by the DOJ, SEC, Baker
Hughes independent monitor or other authorities or the effect the
actions may have on the business or consolidated financial statements of the
combined company. If the DOJ or SEC were to take action for failure to comply with the U.S.
Foreign Corrupt Practices Act or terms of agreements with such agencies, it could significantly
affect our results of operations.
While a settlement has been proposed in connection with the pending stockholder class action
litigation against BJ Services, its directors and certain officers and Baker Hughes in connection
with the merger, the litigation could adversely affect our business, financial condition or results
of operations following the merger if the proposed settlement has not been completed.
Demand for the combined companys products and services, including pressure pumping services, could
be reduced or eliminated by governmental regulation or a change in the law.
Upon completion of the merger, pressure pumping services will account for approximately 20% of
the combined companys revenue. Recently, legislation has been introduced in the United States
Congress that would authorize the Environmental Protection
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Agency to regulate hydraulic fracturing under the Clean Water Act. Such regulations
could greatly reduce or eliminate demand for the combined companys pressure pumping services. If
such regulation were enacted, the combined company could suffer a significant decrease in revenue.
We are unable to predict whether the proposed legislation or any other proposals will ultimately be
enacted, and if so, the impact on the combined companys business.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We are headquartered in Houston, Texas and operate 46 principal manufacturing plants
(including significant equipment repair facilities), ranging in size from approximately 10,000 to
300,000 square feet of manufacturing space. The total aggregate area of the plants is
approximately 3.6 million square feet, of which approximately 2.4 million square feet (65%) are
located in North America, 0.3 million square feet (8%) are located in Latin America, 0.8 million
square feet (23%) are located in Europe, and a minimal amount of space is located in the Middle
East, Asia Pacific region. Our principal manufacturing plants are located in: (i) North America -
Houston, Texas; Broken Arrow, Claremore and Tulsa, Oklahoma; Lafayette, Louisiana; Calgary, Canada;
(ii) Latin America Maracaibo, Venezuela; Mendoza, Argentina; (iii) Europe, Africa, Russia,
Caspian Aberdeen and East Kilbride, Scotland; Celle, Germany; Belfast, Northern Ireland; and (vi)
Middle East, Asia Pacific Dubai, United Arab Emirates.
We own or lease numerous service centers, shops and sales and administrative offices
throughout the geographic regions in which we operate. We also have a significant investment in
service vehicles, rental tools and manufacturing and other equipment. We believe that our
manufacturing facilities are well maintained and suitable for their intended purposes. The table
below shows our principal manufacturing plants by segment and geographic region:
Europe, | ||||||||||||||||||||
Africa, Russia, | Middle East, | |||||||||||||||||||
Segment | North America | Latin America | Caspian | Asia Pacific | Total | |||||||||||||||
Completion and Production |
20 | 3 | 4 | 2 | 29 | |||||||||||||||
Drilling and Evaluation |
10 | 1 | 4 | 2 | 17 |
ITEM 3. LEGAL PROCEEDINGS
The information with respect to Item 3. Legal Proceedings is contained in Note 15 of the Notes
to Consolidated Financial Statements in Item 8 herein. We previously disclosed copies of the
orders, agreements, settlements and deferred prosecution agreement, referenced in Note 15, and the same are incorporated
by reference in this annual report as Exhibits 10.61 and 10.62 and 99.1 through 99.7.
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 19, 2010,
there were approximately 238,600 stockholders and
approximately 14,100 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, 2009, and information regarding
dividends declared on our common stock during the two years ended December 31, 2009, see Note 17 of
the Notes to Consolidated Financial Statements in Item 8 herein.
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The following table contains information about our purchases of equity securities during the
fourth quarter of 2009.
Issuer Purchases of Equity Securities
Total | Maximum | |||||||||||||||||||||||
Number of | Number (or | |||||||||||||||||||||||
Shares | Total | Approximate | ||||||||||||||||||||||
Purchased | Number of | Dollar Value) of | ||||||||||||||||||||||
as Part of a | Shares | Shares that May | ||||||||||||||||||||||
Total Number | Average | Publicly | Average | Purchased | Yet Be | |||||||||||||||||||
of Shares | Price Paid | Announced | Price Paid | in the | Purchased Under | |||||||||||||||||||
Period | Purchased(1) | Per Share(1) | Program(2) | Per Share(2) | Aggregate | the Program(3) | ||||||||||||||||||
October 1-31, 2009 |
7,639 | $ | 45.33 | | $ | | 7,639 | $ | | |||||||||||||||
November 1-30, 2009 |
| | | | | | ||||||||||||||||||
December 1-31, 2009 |
10,932 | 39.09 | | | 10,932 | | ||||||||||||||||||
Total |
18,571 | $ | 41.66 | | $ | | 18,571 | $ | 1,197,127,803 | |||||||||||||||
(1) | Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units. | |
(2) | There were no share repurchases during the three months ended December 31, 2009. | |
(3) | Our Board of Directors has authorized a program to repurchase our common stock from time to time. During the fourth quarter of 2009, we did not repurchase any shares of our common stock. We had authorization remaining to repurchase up to a total of $1,197 million of our common stock. |
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Corporate Performance Graph
The following graph compares the yearly change in our cumulative total stockholder return on
our common stock (assuming reinvestment of dividends into common stock at the date of payment) with
the cumulative total return on the published Standard & Poors 500 Stock Index and the cumulative
total return on Standard & Poors 500 Oil and Gas Equipment and Services Index over the preceding
five-year period.
Comparison of Five-Year Cumulative Total Return *
Baker Hughes Incorporated; S&P 500 Index and S&P 500 Oil and Gas Equipment and Services Index
2004 | 2005 | 2006 | 2007 | 2008 | 2009 | |||||||||||||||||||||||||||
Baker Hughes |
$ | 100.00 | $ | 143.78 | $ | 177.82 | $ | 194.45 | $ | 77.66 | $ | 101.12 | ||||||||||||||||||||
S&P 500 Index |
100.00 | 104.91 | 121.48 | 128.15 | 80.74 | 102.22 | ||||||||||||||||||||||||||
S&P 500 Oil and Gas
Equipment and
Services Index |
100.00 | 148.57 | 171.65 | 253.87 | 103.64 | 165.63 | ||||||||||||||||||||||||||
* | 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, 2004 in Baker Hughes common stock, the
S&P 500 Index and the S&P 500 Oil and Gas Equipment and Services Index.
The Corporate Performance Graph and related information shall not be deemed soliciting
material or to be filed with the SEC, nor shall such information be incorporated by reference
into any future filing under the Securities Act or the Exchange Act, except to the extent that
Baker Hughes specifically incorporates it by reference into such filing.
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ITEM 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial
Statements and Supplementary Data, both contained herein.
Year Ended December 31, | ||||||||||||||||||||
(In millions, except per share amounts) | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||||
Revenues |
$ | 9,664 | $ | 11,864 | $ | 10,428 | $ | 9,027 | $ | 7,185 | ||||||||||
Costs and expenses: |
||||||||||||||||||||
Cost of revenues |
7,397 | 7,954 | 6,845 | 5,876 | 5,024 | |||||||||||||||
Research and engineering |
397 | 426 | 372 | 339 | 300 | |||||||||||||||
Marketing, general and administrative |
1,120 | 1,046 | 933 | 878 | 628 | |||||||||||||||
Acquisition-related costs |
18 | | | | | |||||||||||||||
Litigation settlement |
| 62 | | | | |||||||||||||||
Total costs and expenses |
8,932 | 9,488 | 8,150 | 7,093 | 5,952 | |||||||||||||||
Operating income |
732 | 2,376 | 2,278 | 1,934 | 1,233 | |||||||||||||||
Equity in income of affiliates |
| 2 | 1 | 60 | 100 | |||||||||||||||
Gain on sale of product line |
| 28 | | | | |||||||||||||||
Gain on sale of interest in affiliate |
| | | 1,744 | | |||||||||||||||
Gain (loss) on investments |
4 | (25 | ) | | | | ||||||||||||||
Interest expense |
(131 | ) | (89 | ) | (66 | ) | (69 | ) | (72 | ) | ||||||||||
Interest and dividend income |
6 | 27 | 44 | 68 | 18 | |||||||||||||||
Income from continuing operations before income
taxes |
611 | 2,319 | 2,257 | 3,737 | 1,279 | |||||||||||||||
Income taxes |
(190 | ) | (684 | ) | (743 | ) | (1,338 | ) | (405 | ) | ||||||||||
Income from continuing operations |
421 | 1,635 | 1,514 | 2,399 | 874 | |||||||||||||||
Income from discontinued operations, net of tax |
| | | 20 | 5 | |||||||||||||||
Income before cumulative effect of accounting
change |
421 | 1,635 | 1,514 | 2,419 | 879 | |||||||||||||||
Cumulative effect of accounting change, net of tax |
| | | | (1 | ) | ||||||||||||||
Net income |
$ | 421 | $ | 1,635 | $ | 1,514 | $ | 2,419 | $ | 878 | ||||||||||
Per share of common stock: |
||||||||||||||||||||
Income from continuing operations: |
||||||||||||||||||||
Basic |
$ | 1.36 | $ | 5.32 | $ | 4.76 | $ | 7.26 | $ | 2.58 | ||||||||||
Diluted |
1.36 | 5.30 | 4.73 | 7.21 | 2.56 | |||||||||||||||
Dividends |
0.60 | 0.56 | 0.52 | 0.52 | 0.48 | |||||||||||||||
Balance Sheet Data: |
||||||||||||||||||||
Cash, cash equivalents and short-term investments |
$ | 1,595 | $ | 1,955 | $ | 1,054 | $ | 1,104 | $ | 774 | ||||||||||
Working capital (current assets minus current
liabilities) |
4,612 | 4,634 | 3,837 | 3,346 | 2,479 | |||||||||||||||
Total assets |
11,439 | 11,861 | 9,857 | 8,706 | 7,807 | |||||||||||||||
Long-term debt |
1,785 | 1,775 | 1,069 | 1,074 | 1,078 | |||||||||||||||
Stockholders equity |
7,284 | 6,807 | 6,306 | 5,243 | 4,698 |
Notes To Selected Financial Data | ||
(1) | Gain (loss) on investments. 2009 income from continuing operations includes a $4 million gain on the settlement of auction rate securities (ARS). 2008 income from continuing operations includes a charge for impairment loss of $25 million relating to ARS. | |
(2) | Litigation settlement. 2008 income from continuing operations includes a net charge of $62 million relating to the settlement of litigation with ReedHycalog. | |
(3) | Gain on sale of product line. 2008 income from continuing operations includes $28 million for the gain on the sale of the Completion and Production segments Surface Safety Systems (SSS) product line. | |
(4) | Equity in income of affiliates and gain on sale of interest in affiliate. On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture we formed with Schlumberger in 2000, and recorded a gain of $1,744 million on the sale. | |
(5) | Discontinued operations. The selected financial data includes reclassifications to reflect Baker Supply Products Division, as discontinued operations. |
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ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Managements Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
should be read in conjunction with the consolidated financial statements of Item 8. Financial
Statements and Supplementary Data contained herein.
EXECUTIVE SUMMARY
We are a major supplier of wellbore-related products and technology services and systems and
provide products and services for drilling, formation evaluation, completion and production, and
reservoir technology and consulting to the worldwide oil and natural gas industry. We report our
results under two segments: the Drilling and Evaluation segment and the Completion and Production
segment, which are aligned by product line based upon the types of products and services provided
to our customers and upon the business characteristics of the product lines during business cycles.
Collectively, we refer to the results of these two segments as Oilfield Operations. The primary
driver of our business is our customers capital and operating expenditures dedicated to oil and
natural gas exploration, field development and production. Our business is cyclical and is
dependent upon our customers expectations for future oil and natural gas prices, economic growth,
hydrocarbon demand and estimates of current and future oil and natural gas production.
Prior to May 4, 2009, our business operations were organized primarily through seven product
line divisions and secondarily through four super regions North America; Latin America; Europe,
Africa, Russia, Caspian (EARC); and Middle East, Asia Pacific (MEAP). On May 4, 2009, we
reorganized the Company by geography and product lines. Global operations are now organized into a
number of geomarket organizations, which report into nine region presidents, who in turn report
into two hemisphere presidents. Separately, product-line marketing and technology organizations
report to a president of products and technology. The presidents of the Eastern Hemisphere,
Western Hemisphere, Products and Technology and the Vice President of Supply Chain report to our
Chief Operating Officer. The reorganization of the Company by geography and product lines is
intended to strengthen our client-focused operations by moving management into the countries where
we conduct our business. The product-line organizations will continue to be responsible for
product development and manufacturing, technology, marketing and delivery of solutions for our
customers to advance their reservoir performance. The supply chain organization is responsible for
development of cost-effective procurement and manufacturing of our products and services. The new
organization structure will also improve cross-product-line technology development, sales processes
and integrated operations capabilities. As of December 31, 2009, we had approximately 34,400
employees, with approximately 61% of these employees working outside the United States.
During 2009, as the global economy continued to weaken many of our customers reduced their
2009 exploration and development spending, and we saw significant decreases from peak drilling
activity, particularly in the U.S. land market and Canada. In addition, we experienced declines in
prices for our products and services.
For 2009 we generated revenues of $9.66 billion, which is down $2.20 billion or 19% compared
to 2008 and compared to a 31% decrease in the worldwide average rig count for the same time period.
Our North American revenues for 2009 were $3.58 billion, a decrease of 31% compared to a 42%
decrease in the average rig counts in both the U.S. and Canada, which reflects the severe
contraction in customer spending and activity. Revenues outside of North America were $6.08
billion, a decrease of 9% compared to 2008. As a result of the decline in activity and
contractions in customer spending, during 2009 we took actions to adjust our operating cost base,
which consisted primarily of reductions in workforce. In connection with the reductions in
workforce, we recorded expenses of $92 million in 2009 related to employee severance costs. Net
income for 2009 was $421 million compared to $1.64 billion in 2008.
In late 2009 and early 2010, there was a modest improvement in the outlook for the global
economy. In response to higher prices for oil and natural gas, many of our North American
customers are anticipating an increase in drilling activity from year-end 2009 levels. While crude
prices in the $70-$80/Bbl range are adequate to support many international projects, the outlook
for international activity will be influenced by the degree to which the global economy improves,
driving demand for oil and natural gas.
PENDING MERGER WITH BJ SERVICES
On August 30, 2009, the Company and BJ Services entered into a merger agreement pursuant to
which the Company will acquire 100% of the outstanding common stock of BJ Services. We have
estimated the total consideration expected to be issued and paid in the merger to be approximately
$6.4 billion, consisting of approximately $0.8 billion to be paid in cash and approximately $5.6
billion to be paid through the issuance of approximately 118 million shares of Baker Hughes common
stock valued at the February 11, 2010 closing Baker Hughes share price of $46.68 per share.
Subject to satisfaction of conditions to closing, it is anticipated that closing of the transaction
will occur in March 2010; however, we cannot guarantee when or if the merger will be
completed or that, if completed, it will be exactly on the terms as set forth in the merger
agreement.
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BJ Services is a Delaware corporation formed in 1990. BJ Services is a leading provider of
pressure pumping and oilfield services for the petroleum industry. BJ Services pressure pumping
services consist of cementing and stimulation services used in the completion of new oil and
natural gas wells and in remedial work on existing wells, both onshore and offshore. BJ Services
oilfield services include casing and tubular services, precommissioning, maintenance and turnaround
services in the pipeline and process business, including pipeline inspection, chemical services,
completion tools and completion fluids.
BUSINESS ENVIRONMENT
Our business environment and its corresponding operating results are affected significantly 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 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.
In 2009, the impact of the global economic recession and the associated decline in oil and
natural gas consumption and energy prices resulted in significant decreases in capital spending by
our customers for exploration for and development of oil and natural gas resources. In the first
half of 2009, spending continued to decline from the peak levels of September 2008 as evidenced by
a 57% drop in the U.S. rig count from a peak of 2,031 rigs in September 2008 to a low of 876 rigs
in June 2009 and a 15% drop in the international rig count from a peak of 1,108 rigs in September
2008 to a low of 947 rigs in August 2009. Prices for our products and services, particularly in
the Drilling and Evaluation segment, declined significantly in the first half of 2009. In the
second half of 2009, oil-driven activity began to increase in both the U.S. and international
markets as oil prices improved and as the market began to anticipate a recovery of economic
activity.
Oil and Natural Gas Prices
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.
2009 | 2008 | 2007 | ||||||||||
Oil prices ($/Bbl) |
$ | 61.99 | $ | 99.92 | $ | 72.23 | ||||||
Natural gas prices ($/mmBtu) |
3.94 | 8.89 | 6.96 |
Oil prices averaged $61.99/Bbl in 2009. The year 2009 began with oil prices trading near
$46/Bbl in early January. In response to a weakening outlook for the worldwide economy and for oil
consumption, oil prices decreased through early February reaching a low for the year of $33.98/Bbl.
In mid-2009, oil prices began to increase, driven in part by an improving outlook for the global
economy. Oil prices reached a high of $81.04 /Bbl in late October, thereafter trading in the
mid-to-high $70/Bbl range for the balance of the year.
Natural gas prices averaged $3.94/mmBtu for the year 2009. The year 2009 began with natural
gas prices in the high $5/mmBtu range. However, weakness in the U.S. economy and expectations for
a decline in demand, particularly in the industrial sector, led to weakening gas prices through the
third quarter of the year. In early September, the price of natural gas hit a low for the year of
$1.88/mmBtu as strong production data, coupled with a weak demand outlook, led to expectations that
natural gas inventories would rise to record levels at the end of the annual injection season.
Natural gas prices increased in late December as colder-than-normal temperatures led to strong
withdrawals of natural gas from storage.
Rig Counts
Baker Hughes has 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 and/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 is not readily
available.
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 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
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available, we compute a weekly or daily average of active rigs. In 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, rigging up, being
used in non-drilling activities, including production testing, completion and workover, and are not
expected to be significant consumers of drill bits.
Our rig counts are summarized in the table below as averages for each of the periods
indicated.
2009 | 2008 | 2007 | ||||||||||
U.S. land and inland waters |
1,046 | 1,814 | 1,695 | |||||||||
U.S. offshore |
44 | 65 | 73 | |||||||||
Canada |
222 | 382 | 343 | |||||||||
North America |
1,312 | 2,261 | 2,111 | |||||||||
Latin America |
356 | 384 | 355 | |||||||||
North Sea |
43 | 45 | 48 | |||||||||
Other Europe |
41 | 53 | 29 | |||||||||
Africa |
62 | 65 | 66 | |||||||||
Middle East |
252 | 280 | 265 | |||||||||
Asia Pacific |
243 | 252 | 241 | |||||||||
Outside North America |
997 | 1,079 | 1,004 | |||||||||
Worldwide |
2,309 | 3,340 | 3,115 | |||||||||
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. In addition, the discussions below for revenues and cost
of revenues are on a combined basis as the business drivers for the individual components of
product sales and service and rentals are similar.
The table below details certain consolidated statement of operations data and their percentage
of revenues (dollar amounts in millions).
2009 | 2008 | 2007 | ||||||||||||||||||||||
$ | % | $ | % | $ | % | |||||||||||||||||||
Revenues |
$ | 9,664 | 100 | % | $ | 11,864 | 100 | % | $ | 10,428 | 100 | % | ||||||||||||
Cost of revenues |
7,397 | 77 | % | 7,954 | 67 | % | 6,845 | 66 | % | |||||||||||||||
Research and engineering |
397 | 4 | % | 426 | 4 | % | 372 | 4 | % | |||||||||||||||
Marketing, general and administrative |
1,120 | 12 | % | 1,046 | 9 | % | 933 | 9 | % |
Revenues:
2009 Compared to 2008
Twelve Months Ended | ||||||||||||||||
December 31, | Increase | |||||||||||||||
2009 | 2008 | (decrease) | % Change | |||||||||||||
Geographic Revenues: |
||||||||||||||||
North America |
$ | 3,584 | $ | 5,178 | $ | (1,594 | ) | (31 | )% | |||||||
Latin America |
1,134 | 1,127 | 7 | 1 | % | |||||||||||
Europe, Africa, Russia, Caspian |
2,925 | 3,386 | (461 | ) | (14 | )% | ||||||||||
Middle East, Asia Pacific |
2,021 | 2,173 | (152 | ) | (7 | )% | ||||||||||
Total revenues |
$ | 9,664 | $ | 11,864 | $ | (2,200 | ) | (19 | )% | |||||||
Revenues for 2009 decreased $2.20 billion or 19% compared to 2008 primarily due to a decrease
in activity as evidenced by a 31% decline in the worldwide rig count, and to a lesser extent,
pricing pressure on our products and services.
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North America
Revenues in North America, which accounted for 37% of total revenues, decreased 31% in 2009
compared to 2008, due to a sharp reduction in rig count and activity. U.S. revenues from our
Drilling & Evaluation segment decreased 47% in 2009, compared to a 42% reduction in the U.S. land
and inland water rig count and a 32% reduction in the U.S. offshore rig count. U.S. revenues from
our Completion & Production segment, which is impacted less by changes in the rig count, were down
16% in 2009 compared to 2008. Canada revenues decreased 23% compared to a 42% decrease in the rig
count reflecting challenging economics for Canadian natural gas producers.
Outside North America
Revenues outside North America, which accounted for 63% of total revenues, decreased 9% in
2009 compared to 2008, in line with the 8% decrease in the rig count outside North America
Latin America revenues increased 1% compared to a 7% decrease in the rig count. The improved
revenue in Latin America was led by directional drilling systems in Mexico/Central America,
Brazil and the Andean geomarkets; drilling fluids in the Brazil geomarket; and drill bits and completions and
production systems in the Mexico/Central America geomarket.
Europe, Africa, Russia, Caspian revenues decreased 14% in 2009 compared to 2008.
The revenue decline in the region was broad-based, across all product lines and geographies within the
region. The largest revenue decreases occurred in the Russia, U.K., Norway and Caspian geomarkets.
Middle East, Asia Pacific revenues decreased 7% in 2009 compared to 2008. Middle East
revenues decreased 11% compared to a 10% decrease in the rig count. Asia Pacific revenues were
down 3% in line with a 4% decrease in the rig count. The largest revenue declines occurred in the
Saudi Arabia/Bahrain, Egypt, Indonesia and North Asia geomarkets.
2008 Compared to 2007
Twelve Months Ended | ||||||||||||||||
December 31, | Increase | |||||||||||||||
2008 | 2007 | (decrease) | % Change | |||||||||||||
Geographic Revenues: |
||||||||||||||||
North America |
$ | 5,178 | $ | 4,441 | $ | 737 | 17 | % | ||||||||
Latin America |
1,127 | 903 | 224 | 25 | % | |||||||||||
Europe, Africa, Russia, Caspian |
3,386 | 3,076 | 310 | 10 | % | |||||||||||
Middle East, Asia Pacific |
2,173 | 2,008 | 165 | 8 | % | |||||||||||
Total revenues |
$ | 11,864 | $ | 10,428 | $ | 1,436 | 14 | % | ||||||||
Revenues for 2008 increased 14% compared to 2007 primarily due to increases in activity in
certain geographic areas, as evidenced by a 7% increase in the worldwide rig count, price
improvement and changes in market share in selected product lines and geographic areas. These
increases were partially offset by the impact of hurricanes in the Gulf of Mexico.
North America
Revenues in North America, which accounted for 44% of total revenues, increased 17% in 2008
compared to 2007, despite the unfavorable impact on our U.S. offshore revenues from
hurricane-related disruptions in 2008. The improvement in North America revenues was led by our
Completion and Production segment and directional drilling, as evidenced by a 7% increase in the
U.S. rig count for land and inland water drilling. The U.S. offshore rig count was down 11% due to
the continued migration of rigs out of the Gulf of Mexico to more attractive international markets
and weather-related disruptions. Canada revenues increased 12% compared to an 11% increase in the
rig count reflecting improved economics for Canadian natural gas producers.
Outside North America
Revenues outside North America, which accounted for 56% of total revenues, increased 12% in
2008 compared to 2007. This increase reflected the improvement in international drilling activity,
as evidenced by a 7% increase in the rig count outside North America, and market share gains in
certain geographic areas.
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Latin America revenues increased 25% compared to an 8% increase in the rig count. The
improved revenue in Latin America was led by directional drilling systems in Brazil and Colombia;
completions and production systems in Mexico; and drill bits throughout the region.
Europe, Africa, Russia, Caspian revenues increased 10%. The improved revenue in the region
was led by all product lines across both segments in Norway and Libya; and completion systems as
well as multiple product lines in the Drilling and Evaluation segment in both Kazakhstan and Russia
partially offset by lower drilling activity in the U.K.
Middle East, Asia Pacific revenues increased 8%. Middle East revenues increased 9% compared
to a 6% increase in the rig count. Asia Pacific revenues were up 7% compared to a 5% increase in
the rig count. The improvement in revenues from the region was led by our Completion and
Production segment in China and sales of various other product lines throughout the region
including Oman and United Arab Emirates.
Cost of Revenues
Cost of revenues as a percentage of revenues was 77% and 67% for 2009 and 2008, respectively.
The increase was primarily due to significant declines in activity worldwide resulting in excess
manufacturing capacity, lower utilization of our rental tools and price deterioration, primarily in
North America. Additional contributing factors to this increase include costs associated with
employee severance of $73 million; an increase in the net provision for doubtful accounts of $73
million; and a change in the geographic and product mix from the sale of our products and services
as we continue to emphasize productivity and cost improvements.
Cost of revenues as a percentage of revenues was 67% and 66% for 2008 and 2007, respectively.
The increase was primarily due to a change in the geographic and product mix from the sale of our
products and services and increasingly competitive conditions and pricing pressures, particularly
in North America. In addition, higher raw material costs and labor costs contributed to the
increase.
Research and Engineering
Research and engineering expenses decreased 7% in 2009 compared with 2008. The decrease is in
line with the decrease in activity; however, we continue to be committed to developing and
commercializing new technologies as well as investing in our core product offerings. The decrease
is offset by $5 million associated with employee severance. Research and development costs
decreased 12% in 2009 compared with 2008.
Research and engineering expenses increased 15% in 2008 compared with 2007. Research and
development costs increased 12% in 2008 compared with 2007. During 2007, we opened the first phase
of the Center for Technology and Innovation in Houston, Texas. This facility focuses on research
and development of completion and production systems in harsh environments. The second phase was
completed in 2008.
Marketing, General and Administrative
Marketing, general and administrative (MG&A) expenses increased 7% in 2009 compared with
2008. This increase resulted primarily from an increase in costs associated with enterprise-wide
accounting system implementations and reorganization activities of $46 million, and employee
severance of $14 million. These increases were partially offset by lower marketing and compliance
related expenses.
MG&A expenses increased 12% in 2008 compared with 2007. This increase corresponds with
increased activity and resulted primarily from higher employee related costs including
compensation, training and benefits, higher marketing expenses as a result of increased activity
and an increase in legal, tax and other compliance related expenses. These increases were
partially offset by foreign exchange gains.
Litigation Settlement
In connection with the settlement of litigation with ReedHycalog, in June 2008, the Company
paid ReedHycalog $70 million in royalties for prior use of certain patented technologies, and
ReedHycalog paid the Company $8 million in royalties for the license of certain Company patented
technologies. The net pre-tax charge of $62 million for the settlement of this litigation is
reflected in the 2008 consolidated statement of operations. See Note 15. Commitment and
Contingencies Litigation in the Notes to Consolidated Financial Statements in Item 8 herein.
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Gain on Sale of Product Line
In February 2008, we sold the assets associated with the Completion and Production segments
Surface Safety Systems (SSS) product line and received cash proceeds of $31 million. The SSS
assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We
recorded a pre-tax gain of $28 million ($18 million after-tax).
Gain (Loss) on Investments
The Company had investments in auction rate securities (ARS) that represent interests in
three variable rate debt securities. These are credit linked notes and generally combine low risk
assets and credit default swaps (CDS) to create a security that pays interest from the assets
coupon payments and the periodic sale proceeds of the CDS. Since September 2007, we had been
unable to sell our ARS investments because of unsuccessful auctions. We estimated the fair value
of our ARS investments based on the underlying structure of each security and their collateral
values, including assessments of counterparty credit quality, default risk underlying the security,
expected cash flows, discount rates and overall capital market liquidity. In December 2008, we
recorded an impairment loss of $25 million, to record the ARS to fair value. In December 2009, we
sold the ARS for $15 million and recorded a gain of $4 million.
Interest Expense and Interest and Dividend Income
Interest expense increased $42 million in 2009 compared with 2008 and increased $23 million in
2008 compared with 2007. These increases are primarily due to the new long-term debt issuances of
$1.25 billion in October 2008, resulting in higher average debt levels throughout 2009 and 2008.
Interest and dividend income decreased $21 million in 2009 compared with 2008 and decreased
$17 million in 2008 compared with 2007. The decrease in both years was primarily due to a
reduction of the average interest rate earned, partially offset by an increase in the average
investment balance.
Income Taxes
Our effective tax rates in 2009, 2008 and 2007 are 31.1%, 29.5%, and 32.9% respectively, which
are lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain
international operations offset by state income taxes.
Our tax filings for various periods are subject to audit by the tax authorities in most
jurisdictions where we conduct business. These audits may result in assessment of additional taxes
that are resolved with the authorities or through the courts. We believe these assessments may
occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have
received tax assessments from various taxing authorities and are currently at varying stages of
appeals and/or litigation regarding these matters. We believe we have substantial defenses to the
questions being raised and will pursue all legal remedies should an unfavorable outcome result.
However, resolution of these matters involves uncertainties and there are no assurances that the
outcomes will be favorable. We provide for uncertain tax positions pursuant to Accounting
Standards Codification (ASC) 740, Income Taxes.
OUTLOOK
This section should be read in conjunction with the factors described in Part I, Item 1A.
Risk Factors and in the Forward-Looking Statements section in this Part I, Item 7, both
contained herein. These factors could impact, either positively or negatively, our expectation
for: oil and natural gas demand; oil and natural gas prices; exploration and development spending
and drilling activity; and production spending.
Our industry is cyclical, and past cycles have been driven primarily by alternating periods of
ample supply or shortage of oil and natural gas relative to demand. As an oilfield services
company, our revenue is dependent on spending by our customers for oil and natural gas exploration,
field development and production. This spending is dependent on a number of factors, including our
customers forecasts of future energy demand, their expectations for future energy prices, their
access to resources to develop and produce oil and gas and their ability to fund their capital
programs.
The recovery from the global economic recession is expected to be the primary driver impacting
the 2010 business environment. As the worldwide economy recovers, demand for hydrocarbons will
increase. The largest incremental demands for oil are expected to be generated by China, India and
the Middle East. Increasing oil demand along with the weakness in the U.S. Dollar relative to
other currencies is expected to support oil prices between $60/Bbl and $85/Bbl. In North America,
the 12-month futures price for natural gas, as quoted in February 2010, has been trading above
$6/mmBtu, offering operators an opportunity to hedge future gas production and lock-in an
attractive return regardless of near-term spot prices. As a result of improved cash flow and
outlook for stronger
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economic growth, our customers are expected to increase their spending to explore for and
develop oil and natural gas in 2010 compared to 2009. Capital discipline on the part of our
competitors, attrition of existing rental fleets and rising demand are expected to result in an
environment that we believe will support increasing prices for our products and services in some
markets by the second half of 2010.
Our outlook for exploration and development spending is based upon our expectations for
customer spending in the markets in which we operate, and is driven primarily by our perception of
industry expectations for oil and natural gas prices and their likely impact on customer capital
and operating budgets as well as other factors that could impact the economic return oil and gas
companies expect for developing oil and gas reserves. Our forecasts are based on our analysis of
information provided by our customers as well as market research and analyst reports including the
Short Term Energy Outlook (STEO) published by the Energy Information Administration of the U.S.
Department of Energy (DOE), the Oil Market Report published by the IEA and the Monthly Oil Market
Report published by OPEC. Our outlook for economic growth is based on our analysis of information
published by a number of sources including the International Monetary Fund (IMF), the
Organization for Economic Cooperation and Development (OECD) and the World Bank.
In North America, the outlook for spending in 2010 will be significantly influenced by the
outlook for the natural gas industry. The lack of recovery in industrial demand for natural gas in
conjunction with a rebound in the gas-directed rig count from mid-2009 lows and continued advances
in horizontal drilling and advanced fracturing and completion technologies has led to increasing
rates of initial production in the unconventional gas fields, resulting in high levels of gas
production relative to demand. Natural gas prices have recovered from low levels reached in the
third and fourth quarters of 2009 in response to colder weather throughout much of the U.S. The
increase in oil-directed drilling in the U.S. reflects the rise in oil prices from low levels in
the first half of 2009.
Expectations for Oil Prices - Due to improved expectations for the global economy, demand for
oil is expected to increase in a range from 0.8 million to 1.1 million barrels per day in 2010
relative to 2009. Non-OPEC supply growth is expected to increase modestly in 2010 related to 2009
and is expected to increase in a range of between 100 thousand to 310 thousand barrels per day.
Decreased demand and moderate growth in non-OPEC production are expected to pressure OPEC to manage
its production levels to support oil prices. Inventories and spare productive capacity, which
buffer oil markets from supply disruptions, are expected to increase as the gap between increasing
supply and decreasing demand grows. In its February 2010 STEO report, the DOE forecasted oil
prices (West Texas Intermediate) to average $81/Bbl in the second half of 2010, increasing to an
average of $84/Bbl in 2011.
Expectations for North America Natural Gas Prices - The lack of overall demand growth,
increasing gas-directed rig count and improving rates of initial production from new gas wells are
expected to keep natural gas prices from increasing dramatically in 2010. In its February 2010
STEO report, the DOE forecasted that U.S. natural gas prices would average $5.37/mmBTU in 2010.
The DOE forecasts gas prices to increase to an average of $5.86/mmBTU in 2011.
Our capital expenditures are expected to be approximately $1.1 billion to $1.2 billion for
2010, including approximately $350 million to $400 million that we expect to spend on
infrastructure, primarily outside North America, but excluding the pending BJ Services merger and
any other acquisitions. A significant portion of our planned capital expenditures can be adjusted
to reflect changes in our expectations for future customer spending. We expect to manage our
capital expenditures to match market demand.
COMPLIANCE
We do business in over 90 countries, including approximately one-half of the 40 countries
having the lowest scores, which indicates high levels of corruption, in Transparency
Internationals Corruption Perception Index survey for 2009. We devote significant resources to
the development, maintenance and enforcement of our Business Code of Conduct policy, our
anti-bribery compliance policies, our internal control processes and procedures and other
compliance related policies. Notwithstanding the devotion of such resources, and in part as a
consequence thereof, from time to time we discover or receive information alleging potential
violations of laws and regulations, including the FCPA and our policies, processes and procedures.
We conduct internal investigations of these potential violations and take appropriate action
depending upon the outcome of the investigation.
We anticipate that the devotion of significant resources to compliance-related issues,
including the necessity for investigations, will continue to be an aspect of doing business in a
number of the countries in which oil and natural gas exploration, development and production take
place and in which we are requested to conduct operations. Compliance-related issues have limited
our ability to do business and/or have raised the cost of operating in these countries. In order
to provide products and services in some of these countries, we may in the future utilize ventures
with third parties, sell products to distributors or otherwise modify our business approach in
order to improve our ability to conduct our business in accordance with applicable laws and
regulations and our Business Code of Conduct.
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Our Best-in-Class Global Ethics and Compliance Program (Compliance Program) is based on (i)
our Core Values of Integrity, Performance, Teamwork and Learning; (ii) the standards contained in
our Business Code of Conduct; (iii) the laws of the countries where we operate; and (iv) our
commitments to the DOJ and the SEC. Our Compliance Program is referenced within the Company as
C2 or Completely Compliant. The Completely Compliant theme is intended to establish
the proper Tone-at-the-Top throughout the Company. Employees are consistently reminded that they
play a crucial role in ensuring that the Company always conducts its business ethically, legally
and safely.
Our Chief Compliance Officer (CCO) oversees the development, administration and enforcement
of our Business Code of Conduct, as well as legal compliance standards, policies, procedures and
processes. The CCO reports directly to the Senior Vice President and General Counsel and the
Chairman of the Audit/Ethics Committee of our Board of Directors. The CCO has ready access to all
of the other senior officers of the Company. Our legal compliance group
includes our CCO, International Trade Counsel, Region Compliance Counsel,
FCPA due diligence counsel, specialized investigative counsel, as well as labor and employment
counsel. The legal compliance group and our other company attorneys located throughout the world
are available to answer legal questions regarding the Compliance Program and provide assistance to
employees.
In connection with our settlements with the DOJ and SEC, we retained an independent monitor
(the Monitor) to assess and make recommendations about our compliance policies and procedures.
The Monitor is required to perform two follow up reviews and to certify whether the anti-bribery
compliance program of Baker Hughes, including its policies and procedures, is appropriately
designed and implemented to ensure compliance with the FCPA, U.S. commercial bribery laws and
foreign bribery laws. On April 8, 2009, the Monitor issued his report for the first of such
follow up reviews and the Monitor issued his certification that our compliance program is
appropriately designed and implemented to ensure such compliance. In response to the Monitors
initial recommendations, we enhanced and added several elements to our overall Compliance Program.
Highlights of our Compliance Program, including enhancements or additions as a result of the
independent monitors recommendations, include the following:
| We have a comprehensive employee compliance training program covering substantially all employees. This includes requiring all employees to take web-based FCPA training and testing modules, which are available in numerous languages; mandatory global, in-person, customized training on anti-bribery compliance for key managers, customs/logistics personnel, sponsors of commercial sales representatives, persons dealing with petty cash, invoice coding and approval, and expense account approval, sales/marketing personnel dealing with national oil companies and specially designed training for all new employees. In addition, our programs allow us to verify the prompt training of new employees regarding our Core Values, Business Code of Conduct and Compliance Standards; | ||
| We have comprehensive internal policies over such areas as facilitating payments; travel, entertainment, gifts and charitable donations connected to non-U.S. government officials; payments to non-U.S. commercial sales representatives; due diligence procedures for commercial sales representatives, processing consultants and professional consultants; non-U.S. community contributions; real estate transactions in selected countries; and the use of non-U.S. police or military organizations for security purposes. In addition, we have country-specific guidance for customs standards, export and re-export controls, economic sanctions and antiboycott laws; | ||
| We have a special compliance committee, which is made up of senior officers, that meets no less than twice a year to review the oversight reports for all active commercial sales representatives; | ||
| We use technology to monitor and report on compliance matters, including a web-based antiboycott reporting tool and a global trade management software tool; | ||
| We have a whistleblower program designed to encourage reporting of any ethics or compliance matter without fear of retaliation including a worldwide Business Helpline operated by a third party and currently available toll-free in 150 languages to ensure that our helpline is easily accessible to employees in their own language; | ||
| We have a Blue Ribbon Panel comprised of well-known outside experts advising us in the areas of securities and compliance laws; | ||
| We have continued our reduction of the use of commercial sales representatives (CSRs) and processing agents, including the reduction of customs agents. We have also continued to enhance our channels of communication regarding agents while streamlining our compliance due diligence process for agents, including more clearly delineating the responsibilities of participants in the compliance due diligence process. We have adopted a risk-based compliance due diligence procedure for professional agents, enhancing our process for classifying distributors and creating a formal policy to guide business |
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personnel in determining when subcontractors should be subjected to compliance due diligence. We have also instituted a program to ensure that each of our internal sponsors regularly reviews their CSRs, including a review with senior management; |
| We have adopted a risk-based compliance due diligence procedure for processing and professional agents, enhancing our process for classifying distributors and creating a formal policy to guide business personnel in determining when subcontractors should be subjected to compliance due diligence; |
| We have reviewed and expanded the use of our centralized finance organization including further implementation of our enterprise-wide accounting system and company-wide policies regarding expense reporting, petty cash, the approval of invoice payments and general ledger account coding. We also have consolidated our divisional audit functions and redeployed some of these resources for corporate audits. Further, we have restructured our corporate audit function, and are incorporating additional anti-corruption procedures into some of our audits, which are applied on a country-wide basis. We are also continuing to refine and enhance our procedures for FCPA compliance reviews, risk assessments, and legal audit procedures; |
| We continue to work to ensure that we have adequate legal compliance coverage around the world, including the coordination of compliance advice and training across all regions and countries where we do business. We have also worked to create simplified summaries, flow charts, and FAQs (Frequently Asked Questions) to accompany each of our compliance related policies and we are supplementing our existing policies. At the same time, we are taking steps to achieve further centralization of our customs and logistics function including the development of uniform and simplified customs policies and procedures. We are also developing uniform procedures for the verification and documentation of services provided by customs agents and a training program in which customs and logistics personnel receive specialized training focused specifically on risks associated with the customs process. We have also adopted a written plan for reviewing and reducing the number of our customs agents and freight forwarders; |
| We are continuing to centralize our human resources function, including creating consistent standards for pre-hire screening of employees, the screening of existing employees prior to promoting them to positions where they may be exposed to corruption-related risks, and creating a uniform policy for on-boarding training. We are implementing a training program that identifies employees for compliance training and sets appropriate training schedules based on job function and risk profile in addition to employment grade. Further, the contents of our training programs are being tailored to address the different risks posed by different categories of employees. We are supplementing our FCPA electronic training module while taking steps to ensure that training is available in the principal local languages of our employees and that local anti-corruption laws are discussed as part of our compliance training. We have also worked to ensure that our helpline is easily accessible to employees in their own language as well as taking actions to counter any cultural norms that might discourage employees from using the helpline. We continue to provide a regular and consistent message from senior management that compliance with our Code of Conduct is obligatory, everyone at Baker Hughes is accountable for upholding its requirements, and emphasizes that compliance is a positive factor in the continued success of our business. |
LIQUIDITY AND CAPITAL RESOURCES
Our objective in financing our business is to maintain adequate financial resources and access
to sufficient liquidity. At December 31, 2009, we had cash and cash equivalents of $1.59 billion
and $1.0 billion available for borrowing under committed revolving credit facilities with
commercial banks. We have a shelf registration statement on file with
the SEC, which positions us to raise additional funds in the capital
market as deemed appropriate.
During the first half of 2009, the declines in commodity prices led to reductions in cash
flows of many of our customers. In addition, the tight credit markets and increased costs of
borrowing affected the availability of credit. These factors may have adverse effects on the
financial condition of our customers, which may result in delays, partial payment or non-payment of
amounts owed to us thus negatively impacting our operating cash flows. During the second half of
2009, the capital markets improved and allowed some of our customers renewed access.
Our capital planning process is focused on utilizing cash flows generated from operations in
ways that enhance the value of our company. In 2009, we used cash to pay for a variety of
activities including working capital needs, dividends, debt maturities and capital expenditures.
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Cash Flows
Cash flows provided (used) by continuing operations by type of activity were as follows for
the years ended December 31 (in millions):
2009 | 2008 | 2007 | ||||||||||
Operating activities |
$ | 1,239 | $ | 1,614 | $ | 1,475 | ||||||
Investing activities |
(966 | ) | (1,170 | ) | (620 | ) | ||||||
Financing activities |
(675 | ) | 541 | (593 | ) |
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 equal the changes in corresponding accounts on
the consolidated balance sheets.
Operating Activities
Cash flows from operating activities provided $1,239 million for the year ended
December 31, 2009 compared with $1,614 million for the year ended December 31, 2008. This decrease
in cash flows of $375 million is primarily due to a decrease in net income offset by the change in
net operating assets and liabilities that provided more cash in 2009 compared to 2008.
The underlying drivers in 2009 of the changes in operating assets and liabilities are as
follows:
| A decrease in accounts receivable provided $399 million in cash compared with using $515 million in 2008. The change in accounts receivable was primarily due to the decrease in activity offset by an increase in the days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) by approximately nine days, reflecting a slowdown in customer payments. |
| Inventory provided $240 million in cash compared with using $371 million in 2008 due to activity decreases. |
| A decrease in accounts payable used $89 million in cash in 2009 compared with providing $242 million in cash in 2008. This decrease in accounts payable corresponds with the decrease in operating assets to support decreased activity. |
| Accrued employee compensation and other accrued liabilities used $130 million in cash in 2009 compared with providing $90 million in cash in 2008. The change was primarily due to an increase in payments in 2009 compared to 2008 primarily related to employee bonuses earned in 2008 but paid in 2009. |
| Our contributions to our defined benefit pension plans in 2009 and 2008 totaled $15 million in each year. |
Cash flows from operating activities of continuing operations provided $1,614 million for the
year ended December 31, 2008 compared with $1,475 million for the year ended December 31, 2007.
Cash flows from operating activities for 2007 were reduced by $125 million for income tax payments
related to the gain on the sale of our interest in WesternGeco. Excluding these income tax
payments, cash flows from operating activities for 2007 were $1,600 million increasing only
slightly in 2008.
The underlying drivers in 2008 of the changes in operating assets and liabilities are as
follows:
| An increase in accounts receivable used $515 million in cash in 2008 compared with using $309 million in cash in 2007. This increase in accounts receivable was primarily due to the increase in revenues. Days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) remained flat. |
| A build up in inventory related to increased activity used $371 million in cash in 2008 compared with using $142 million in cash in 2007. |
| An increase in accounts payable provided $242 million in cash in 2008 compared with providing $26 million in cash in 2007. This increase in accounts payable was primarily due to an increase in operating assets to support increased activity. |
| Accrued employee compensation and other accrued liabilities provided $90 million in cash in 2008 compared with using $139 million in cash in 2007. The increase in cash was primarily due to payments made in 2007 that were greater than payments |
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made in 2008 including payments related to employee bonuses, non-income tax liabilities and the payment of $44 million related to the settlement of the investigations by the SEC and DOJ. |
| Our contributions to our defined benefit pension plans in 2008 were $15 million compared to 2007 contributions of $21 million, a decrease of $6 million driven primarily by the change in exchange rates in non-U.S. locations. |
Investing Activities
Our principal recurring investing activity is the funding of capital expenditures to support
the appropriate levels and types of rental tools we have in place to generate revenues from
operations. Expenditures for capital assets totaled $1,086 million, $1,303 million and $1,127
million for 2009, 2008 and 2007, respectively. While the majority of these expenditures were for
rental tools, including wireline tools, and machinery and equipment, we have also increased our
spending on new facilities, expansions of existing facilities and other infrastructure projects.
Proceeds from disposal of assets were $163 million, $222 million and $179 million for 2009,
2008 and 2007, 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.
We routinely evaluate potential acquisitions of businesses of third parties that may enhance
our current operations or expand our operations into new markets or product lines. We may also
from time to time sell business operations that are not considered part of our core business.
During 2009, we paid $47 million, net of cash acquired of $4 million, for several acquisitions and
as a result, recorded $9 million of goodwill and $22 million of intangible assets. We also paid
$11 million for additional purchase price consideration for past acquisitions.
In 2008, we paid an aggregate of $120 million for acquisitions of businesses, the most
significant of which were the acquisitions for our reservoir technology and consulting group, in
which we paid cash of $72 million, including $4 million of direct transaction costs and net of cash
acquired of $5 million. As a result of these acquisitions, we recorded $45 million of goodwill and
$45 million of intangible assets.
In 2008, we sold the assets associated with the Completion and Production segments Surface
Safety Systems product line and received cash proceeds of $31 million.
Prior to September 2007, we invested in auction rate securities. We limited our investments
in auction rate securities (ARS) to non mortgage-backed securities that, at the time of the
initial investment, carried an AAA (or equivalent) rating from a recognized rating agency. In
December 2008, we recorded an impairment loss of $25 million on these investments. In December
2009, we sold the ARS for $15 million and recorded a gain of $4 million.
In 2007, we received $10 million in proceeds from the sale of our equity investment in Toyo
Petrolite Company Ltd.
Financing Activities
We had net repayments of commercial paper and other short-term debt of $16 million in 2009,
and net borrowing of commercial paper and short-term debt of $15 million and $14 million in 2008
and 2007, respectively. In addition, in the first quarter of 2009, we repaid $525 million of
maturing long-term debt. Total debt outstanding at December 31, 2009 was $1.80 billion, a decrease
of $533 million compared with December 31, 2008. The total debt to total capitalization (defined
as total debt plus stockholders equity) ratio was 0.20 at December 31, 2009 and 0.25 at
December 31, 2008.
On October 28, 2008, we sold $500 million of 6.50% Senior Notes that will mature
November 15, 2013, and $750 million of 7.50% Senior Notes that will mature November 15, 2018
(collectively, the Notes). Net proceeds from the offering were $1,235 million after deducting
the underwriting discounts and expenses of the offering. We used a portion of the net proceeds to
repay outstanding commercial paper, as well as to repay $325 million aggregate principal amount of
our outstanding 6.25% notes, which matured on January 15, 2009, and $200 million aggregate
principal amount of our outstanding 6.00% notes, which matured on February 15, 2009. We used the
remaining net proceeds from the offering for general corporate purposes. The Notes are senior
unsecured obligations and rank equal in right of payment to all of our existing and future senior
indebtedness; senior in right of payment to any future subordinated indebtedness; and effectively
junior to our future secured indebtedness, if any, and to all existing and future indebtedness of
our subsidiaries. We may redeem, at our option, all or part of the Notes at any time, at the
applicable make-whole redemption prices plus accrued and unpaid interest to the date of redemption.
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We received proceeds of $51 million, $87 million and $67 million in 2009, 2008 and 2007,
respectively, from the issuance of common stock through the exercise of stock options and the
employee stock purchase plan.
Our Board of Directors has authorized a program to repurchase our common stock from time to
time. During 2007, we repurchased 6 million shares of common stock at an average price of $81.25
per share for a total of $521 million. During 2008, we repurchased 9 million shares of our common
stock at an average price of $68.12 per share for a total of $627 million. During 2009, we did not
repurchase any shares of common stock. We had authorization remaining to repurchase approximately
$1.2 billion in common stock at the end of 2009.
We paid dividends of $185 million, $173 million and $167 million in 2009, 2008 and 2007,
respectively.
Available Credit Facilities
On March 30, 2009, we entered into a credit agreement (the 2009 Credit Agreement) for a
committed $500 million revolving credit facility that expires on March 29, 2010, which we currently
expect to extend or replace. In addition to the 2009 Credit Agreement, there is a $500 million
committed revolving credit facility which expires on July 7, 2012. Under a committed facility, the
lender is obligated to advance funds and/or provide credit to the borrower as per the terms and
conditions stipulated in the credit agreement. At December 31, 2009, we had $1.0 billion of
committed revolving credit facilities with commercial banks. Both facilities contain certain
covenants which, among other things, require the maintenance of a funded indebtedness to total
capitalization ratio (a defined formula per the facility), restrict certain merger transactions or
the sale of all or substantially all of our assets or a significant subsidiary and limit the amount
of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations
under the facilities may be accelerated. Such events of default include payment defaults to
lenders under the facilities, covenant defaults and other customary defaults.
At December 31, 2009, we were in compliance with all of the facility covenants of both
committed credit facilities. There were no direct borrowings under the committed credit facilities
at the end of 2009. We also have an outstanding commercial paper program under which we may issue
from time to time up to $1.0 billion in commercial paper with maturity of no more than 270 days.
To the extent we have commercial paper outstanding, our ability to borrow under the committed
credit facilities is reduced by a similar amount. At December 31, 2009, we had no commercial paper
outstanding.
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 rating. There are no ratings triggers that would
accelerate the maturity of any borrowings under our committed credit facilities. However, a
downgrade in our credit ratings could increase the cost of borrowings under the facilities and
could also limit or preclude our ability to issue commercial paper. Should this occur, we would
seek alternative sources of funding, including borrowing under the facilities.
We believe our current credit ratings 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.
Cash Requirements
In 2010, we believe cash on hand and operating cash flows will provide us with sufficient
capital resources and liquidity to manage our working capital needs, meet contractual obligations,
fund capital expenditures, and support the development of our short-term and long-term operating
strategies. We may issue commercial paper or other short-term debt to fund cash needs in the U.S.
in excess of the cash generated in the U.S. The expectations
described below exclude any amounts related to the pending merger
with BJ Services.
In 2010, we expect our capital expenditures to be between approximately $1.1 billion to $1.2 billion,
excluding any amount related to the pending merger with BJ Services and other acquisitions. The
expenditures are expected to be used primarily for normal, recurring items necessary to support our
business and operations. A significant portion of our capital expenditures can be adjusted based
on future activity of our customers. We expect to manage our capital expenditures to match market
demand. In 2010, we also expect to make interest payments of between $129 million and $135
million, based on debt levels as of December 31, 2009. We anticipate making income tax payments of
between $300 million and $350 million in 2010.
We may repurchase our common stock depending on market conditions, applicable legal
requirements, our liquidity and other considerations. We anticipate paying dividends of between
$180 million and $190 million in 2010; however, the Board of Directors can change the dividend
policy at anytime.
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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. Although we
previously expected to forgo contributions for a period of five to eight years, due to recent
downturns in investment markets and the decline in the value of the pension plan assets, we may be
required to make contributions to the U.S. qualified pension plan within the next one to two years.
In 2010, we expect to contribute between $20 million and $25 million to our U.S. pension plans and
between $15 million and $20 million to the non-U.S. pension plans. In 2010, we also expect to make
benefit payments related to postretirement welfare plans of between $18 million and $20 million,
and we estimate we will contribute between $142 million and $154 million to our defined
contribution plans. See Note 14 of the Notes to Consolidated Financial Statements in Item 8 herein
for further discussion of our employee benefit plans.
Cash
Requirements for Pending Merger
Subject to receipt of all required approvals, we currently anticipate that the closing of the
BJ Services merger will occur in March of 2010. In order to fund the estimated $794
million cash portion of the merger consideration, we expect to use approximately $294 million of
our cash on hand and $500 million of our financing through available facilities or market issuances
of debt securities. In addition, we intend to use such internal cash resources and financing as
well as cash on hand of BJ Services following the merger, which at December 31, 2009 was $261
million, to pay for the estimated direct merger transaction costs and professional services as well
as pre-existing change of control contractual payments to certain BJ
Services employees that as of December 31, 2009 was estimated to be
approximately $280 million. Also, in connection with the pending merger we will
assume approximately $500 million of long-term debt of BJ Services and various guarantees and
contractual obligations in place in connection with BJ Services normal course of business.
Following the merger, we may seek additional sources of funding.
Contractual Obligations
In the table below, we set forth our contractual cash obligations as of December 31, 2009.
Certain amounts included in this table are based on our estimates and assumptions about these
obligations, including their duration, anticipated actions by third parties and other factors. The
contractual cash obligations we will actually pay in future periods may vary from those reflected
in the table because the estimates and assumptions are subjective (in millions).
Payments Due by Period | ||||||||||||||||||||
Less Than | 2 - 3 | 4 - 5 | More than | |||||||||||||||||
Total | 1 year | Years | Years | 5 Years | ||||||||||||||||
Total debt (1) |
$ | 1,815 | $ | 15 | $ | | $ | 500 | $ | 1,300 | ||||||||||
Estimated interest payments (2) |
1,352 | 129 | 258 | 224 | 741 | |||||||||||||||
Operating leases(3) |
445 | 126 | 150 | 67 | 102 | |||||||||||||||
Purchase obligations (4) |
221 | 219 | 2 | | | |||||||||||||||
Other long-term liabilities (5) |
53 | 10 | 17 | 5 | 21 | |||||||||||||||
Income tax liabilities for uncertain tax positions (6) |
339 | 115 | 160 | 43 | 21 | |||||||||||||||
Total |
$ | 4,225 | $ | 614 | $ | 587 | $ | 839 | $ | 2,185 | ||||||||||
(1) | Amounts represent the expected cash payments for our total debt and do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements. | |
(2) | Amounts represent the expected cash payments for interest on our long-term debt. | |
(3) | We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the lease. Our future operating lease payments as reflected in the table above would change if we exercised these renewal options and if we entered into additional operating lease agreements. | |
(4) | Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable at anytime without penalty. | |
(5) | Amounts represent other long-term liabilities, including the current portion, reflected in the consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions and payments for various postretirement welfare benefit plans and postemployment benefit plans. |
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(6) | The estimated income tax liabilities for uncertain tax positions will be settled as a result of expiring statutes, audit activity, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of a statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the tax liability would not result in a cash payment. |
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 $692 million at December 31, 2009. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts of approximately $221 million at December 31, 2009. It is not practicable to estimate
the fair value of these financial instruments. None of the off-balance sheet arrangements either
has, or is likely to have, a material effect on our consolidated financial statements.
Other than normal operating leases, we do not have any off-balance sheet financing
arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or
special purpose entities. As such, we are not materially exposed to any financing, liquidity,
market or credit risk that could arise if we had engaged in such financing arrangements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of our consolidated financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues and expenses and
related disclosures and about contingent assets and liabilities. We base these estimates and
judgments on historical experience and other assumptions and information that are believed to be
reasonable under the circumstances. Estimates and assumptions about future events and their
effects cannot be perceived with certainty, and accordingly, these estimates may change as new
events occur, as more experience is acquired, as additional information is obtained and as the
business environment in which we operate changes.
We have defined a critical accounting estimate as one that is both important to the portrayal
of either our financial condition or results of operations and requires us to make difficult,
subjective or complex judgments or estimates about matters that are uncertain. We have discussed
the development and selection of our critical accounting estimates with the Audit/Ethics Committee
of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented
below. During the past three fiscal years, we have not made any material changes in the
methodology used to establish the critical accounting estimates discussed below, except as required
by the adoption of ASC 740, Income Taxes. 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, 2009 and 2008, allowance for doubtful
accounts totaled $157 million, or 6%, and $74 million, or 3%, of total gross accounts receivable,
respectively.
Starting in late 2008 and continuing through the fourth quarter of 2009, we experienced a delay in receiving payments from
our customers in Venezuela resulting in an increase in our provisions for doubtful accounts in 2009.
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 before income taxes of
approximately $8 million in 2009.
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, 2009
and 2008, inventory reserves totaled $297 million, or 14%, and $244
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million, or 11%, of gross
inventory, respectively. We believe that our reserves are adequate to properly value potential
excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes
to our estimates and forecasts could impact the amount and timing of any additional provisions for
excess or obsolete inventory that may be required. A five percent change in this inventory reserve
balance would have had an impact on income before income taxes of approximately $15 million in
2009.
Impairment of Long-Lived Assets
Long-lived assets, which include property, goodwill, intangible assets, 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. We perform our annual impairment test of goodwill as of October 1 of
each year. In performing the test, we individually test each of our seven reporting units. These
tests involve the use of three different valuation techniques, including a market approach,
comparable transactions and discounted cash flow methodology, all of which include, but are not
limited to, assumptions regarding matters such as discount rates, anticipated growth rates and
expected profitability rates and similar items. The results of the 2009 test indicated that there
were no impairments of goodwill; however, for three reporting units, the excess of estimated fair
value over the carrying value was less than 15% of the related carrying value. Goodwill associated
with these three reporting units totaled approximately $394 million at December 31, 2009.
Unanticipated changes, including even small revisions, to these assumptions could require a
provision for impairment in a future period. Given the nature of these evaluations and their
application to specific assets and specific times, it is not possible to reasonably quantify the
impact of changes in these assumptions.
Income Taxes
The liability method is used for determining our income taxes, under which current and
deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.
Under this method, the amounts of deferred tax liabilities and assets at the end of each period are
determined using the tax rate expected to be in effect when taxes are actually paid or recovered.
Valuation allowances are established to reduce deferred tax assets when it is more likely than not
that some portion or all of the deferred tax assets will not be realized. In determining the need
for valuation allowances, we have considered and made judgments and estimates regarding estimated
future taxable income and ongoing prudent and feasible tax planning strategies. These estimates
and judgments include some degree of uncertainty and changes in these estimates and assumptions
could require us to adjust the valuation allowances for our deferred tax assets. Historically,
changes to valuation allowances have been caused by major changes in the business cycle in certain
countries and changes in local country law. The ultimate realization of the deferred tax assets
depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.
We operate in more than 90 countries under many legal forms. As a result, we are subject to
the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and
treaties among these governments. Our operations in these different jurisdictions are taxed on
various bases: actual income before taxes, deemed profits (which are generally determined using a
percentage of revenues rather than profits) and withholding taxes based on revenue. Determination
of taxable income in any jurisdiction requires the interpretation of the related tax laws and
regulations and the use of estimates and assumptions regarding significant future events such as
the amount, timing and character of deductions, permissible revenue recognition methods under the
tax law and the sources and character of income and tax credits. Changes in tax laws, regulations,
agreements and treaties, foreign currency exchange restrictions or our level of operations or
profitability in each taxing jurisdiction could have an impact on the amount of income taxes that
we provide during any given year.
Our tax filings for various periods are subjected to audit by the tax authorities in most
jurisdictions where we conduct business. These audits may result in assessments of additional
taxes that are resolved with the authorities or through the courts. We believe these assessments
may occasionally be based on erroneous and even arbitrary interpretations of local tax law.
Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we
provide taxes only for the amounts we believe will ultimately result from these proceedings
consistent with the requirements of ASC 740, Income Taxes. 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.
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In addition to the aforementioned assessments that have been received from various tax
authorities, we provide for taxes for uncertain tax positions where assessments have not been
received in accordance with ASC 740, Income Taxes. We believe such tax reserves are adequate in
relation to the potential for additional assessments. Once established, we adjust these amounts
only when more information is available or when an event occurs necessitating a change to the
reserves. Future events such as changes in the facts or law, judicial decisions regarding the
application of existing law or a favorable audit outcome will result in changes to the amounts
provided. We believe that the resolution of tax matters will not have a material effect on the
consolidated financial condition of the Company, although a resolution could have a material impact
on our consolidated statement of operations for a particular period and on our effective tax rate
for any period in which such resolution occurs.
Pensions and Postretirement Benefit Obligations
Pensions and postretirement benefit obligations and the related plan expenses are calculated
using actuarial models and methods. This involves the use of two critical assumptions, the
discount rate and the expected rate of return on assets, both of which are important elements in
determining plan expenses and in measuring plan assets and liabilities. We evaluate these critical
assumptions at least annually. Although considered less critical, other assumptions used in
determining benefit obligations and plan expenses, such as demographic factors like retirement age,
mortality and turnover, are also evaluated periodically and are updated to reflect our actual and
expected experience.
The discount rate enables us to state expected future cash flows at a present value on the
measurement date. The development of the discount rate for our U.S. plans was based on a bond
matching model whereby a hypothetical bond portfolio of high-quality, fixed-income securities is
selected that will match the cash flows underlying the projected benefit obligation. The discount
rate assumption for our non-U.S. plans reflects the market rate for high-quality, fixed-income
securities. A lower discount rate increases the present value of benefit obligations and increases
plan expenses. We used a discount rate of 6.4% in 2009 and 6.0% in 2008 and in 2007 to determine
plan expenses. A 50 basis point reduction in the discount rate would have decreased income before
income taxes by approximately $3 million in 2009.
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 8.0% in 2009 and in 2008 and 8.5% in 2007. A 50 basis point reduction in the
expected rate of return on assets of our principal plans would have decreased income before income
taxes by approximately $2 million in 2009.
NEW ACCOUNTING STANDARDS AND ACCOUNTING STANDARDS UPDATES
In June 2009, the Financial Accounting Standards Board (FASB) issued ASC 105, Generally
Accepted Accounting Principles. The ASC identifies itself as the source of authoritative
accounting principles recognized by the FASB to be applied by nongovernmental entities in the
preparation of financial statements in conformity with generally accepted accounting principles in
the United States. Rules and interpretive releases of the SEC under authority of federal
securities laws are also sources of authoritative GAAP. The ASC does not change GAAP, but is
intended to simplify user access to all authoritative GAAP by providing all the authoritative
literature related to a particular topic in one place. This statement is effective for financial
statements issued for interim and annual periods ending after September 15, 2009. We have included
references to authoritative accounting literature in accordance with the Codification. There are
no other changes to the content of the Companys financial statements or disclosures as a result of
the adoption.
In October 2009, the FASB issued an update to ASC 605, Revenue Recognition Multiple
Deliverable Revenue Arrangements. This ASU addresses accounting for multiple-deliverable
arrangements to enable vendors to account for deliverables separately. The provision establishes a
selling price hierarchy for determining the selling price of a deliverable. This update requires
expanded disclosures for multiple deliverable revenue arrangements. The ASU will be effective for
revenue arrangements entered into or materially modified beginning on or after June 15, 2010. We
have not determined the impact, if any, on our consolidated financial statements.
In September 2006, FASB issued ASC 820, Fair Value Measurements and Disclosures, 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. On January 1, 2008, we adopted the provisions of this ASC related to financial
assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a
recurring basis and on January 1, 2009, we adopted the provisions related to nonfinancial assets
and liabilities that are not required or permitted to be measured at fair value on a recurring
basis. There was no material impact to our consolidated financial statements related to these
adoptions. Additionally, in April 2009, the FASB issued the following three accounting standards
updates: (i) ASC 820, Determining Fair Value When the Volume and Level of Activity for the Asset
or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ii)
ASC 320, Recognition and Presentation of Other-Than-Temporary Impairments, and (iii) ASC 825,
Interim Disclosures about Fair Value of
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Financial Instruments, which collectively provide additional guidance and require additional
disclosure regarding determining and reporting fair values for certain assets and liabilities. We
adopted the three accounting standards updates in the second quarter of 2009 with no material
impact to our consolidated financial statements. In September 2009, the FASB issued an update to
ASC 820, Fair Value Measurements and Disclosures Investments in Certain Entities That Calculate
Net Asset Value per Share (or Its Equivalent). The ASU provides a practical means for measuring
the fair value of investments in certain entities that calculate net asset value per share. The
ASU is effective for the first reporting period ending after December 15, 2009. We adopted the
provisions and disclosure requirements of this ASU in December 2009 with no material impact to our
consolidated financial statements.
In December 2007, the FASB issued an update to ASC 810, Consolidation, to establish accounting
and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation
of a subsidiary in an effort to improve the relevance, comparability and transparency of the
financial information that a reporting entity provides. On January 1, 2009, we adopted this
statement with no change to our consolidated financial statements as amounts are immaterial.
In December 2007, the FASB issued an update to ASC 805, Business Combinations, to establish
principles and requirements for the recognition and measurement of assets, liabilities and
goodwill, and requires that most transaction and restructuring costs related to the acquisition be
expensed. We have applied the provisions of this ASC for business combinations with an acquisition
date on or after January 1, 2009.
In March 2008, the FASB issued an update to ASC 815, Disclosures about Derivative Instruments
and Hedging Activities, to require qualitative disclosures about objectives and strategies for
using derivatives and quantitative data about the fair value of and gains and losses on derivative
contracts. We adopted the new disclosure requirements in the first quarter of 2009.
In June 2008, the FASB issued an update to ASC 260, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities, to clarify that all unvested
share-based payments that contain rights to non-forfeitable dividends are participating securities
and shall be included in the computation of both basic and diluted earnings per share. On
January 1, 2009, we adopted this ASC and have not applied the provisions to prior year quarters as
the impact is immaterial.
In December 2008, the FASB issued an update to ASC 715, Employers Disclosures about
Postretirement Benefit Plan Assets, to require the disclosures of investment policies and
strategies, major categories of plan assets, fair value measurement of plan assets and significant
concentration of credit risks. We adopted the new disclosure requirements in the fourth quarter of
2009. See Note 14 of the Notes to Consolidated Financial Statements in Item 8 herein for further
information on the impact of this standard.
RELATED PARTY TRANSACTIONS
There were no significant related party transactions during the three years ended
December 31, 2009.
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, except to
the extent specific disclosure is made with respect to the potential merger with BJ Services. We
undertake no obligation to publicly update or revise any forward-looking statement. Our
expectations regarding our business outlook, including changes in revenue, pricing, capital
spending, profitability, strategies for our operations, impact of any common stock repurchases, oil
and natural gas market conditions, market share and contract terms, costs and availability of
resources, economic and regulatory conditions, the potential merger with BJ Services, 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 Item 1A. Risk Factors and those set forth from time to time in
our filings with the SEC. These documents are available through our website or through the SECs
Electronic Data Gathering and Analysis Retrieval System (EDGAR) at http://www.sec.gov.
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Risk Factors
For discussion of our risk factors and cautions regarding forward-looking statements, see Item
1A. Risk Factors and in the Forward-Looking Statements section in Item 7, both contained herein.
The risk factors and cautions discussed there are not intended to be all inclusive.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks that are inherent in our financial instruments and
arise from changes in interest rates and foreign currency exchange rates. We may enter into
derivative financial instrument transactions to manage or reduce market risk but do not enter into
derivative financial instrument transactions for speculative purposes. A discussion of our primary
market risk exposure in financial instruments is presented below.
INTEREST RATE RISK AND INDEBTEDNESS
We are subject to interest rate risk on our long-term fixed interest rate debt. Commercial
paper borrowings, other short-term borrowings and variable rate long-term debt do not give rise to
significant interest rate risk because these borrowings either have maturities of less than three
months or have variable interest rates similar to the interest rates we receive on our short-term
investments. All other things being equal, the fair market value of debt with a fixed interest
rate will increase as interest rates fall and will decrease as interest rates rise. This exposure
to interest rate risk can be managed by borrowing money that has a variable interest rate or using
interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.
Interest Rate Swap Agreements
In June 2009, we entered into two interest rate swap agreements (the Swap Agreements) for a
notional amount of $250 million each in order to hedge changes in the fair market value of our $500
million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive
interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a
spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap through
November 15, 2013. The Swap Agreements are designated and each qualifies as a fair value hedging
instrument. The fair value of the Swap Agreements at December 31, 2009, was a $7 million asset and
was based on quoted market prices for contracts with similar terms and maturity dates.
The financial institutions that are counterparties to the Swap Agreements are primarily the
lenders in our credit facilities. Under the terms of the credit support documents governing the
Swap Agreements, the relevant party will have to post collateral in the event such partys
long-term debt rating falls below investment grade or is no longer rated.
Indebtedness
We had fixed rate debt aggregating to $1,800 million at December 31, 2009 and $2,325 million
at December 31, 2008. 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, 2009 and 2008 (dollar amounts in millions).
2008 | 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | Total | |||||||||||||||||||||||||
As of December 31, 2009 |
||||||||||||||||||||||||||||||||
Long-term debt (1) (2) |
$ | | $ | | $ | | $ | | $ | | $ | 500 | $ | 1,300 | $ | 1,800 | ||||||||||||||||
Weighted average
effective interest rates |
6.73 | % | 7.61 | % | 7.37 | % | ||||||||||||||||||||||||||
As of December 31, 2008 |
||||||||||||||||||||||||||||||||
Long-term debt (1) (2) |
$ | | $ | 525 | $ | | $ | | $ | | $ | 500 | $ | 1,300 | $ | 2,325 | ||||||||||||||||
Weighted average
effective interest rates |
5.90 | % (3) | 6.73 | % | 7.07 | % | 7.03 | % (3) |
(1) | Amounts do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements. | |
(2) | Fair market value of fixed rate long-term debt was $2,111 million at December 31, 2009 and $2,455 million at December 31, 2008. | |
(3) | Includes the effect of the amortization of net deferred gains on terminated interest rate swap agreements. |
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FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS
We conduct operations around the world in a number of different currencies. The majority 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.
In January 2010, Venezuelas currency was devalued and a new currency exchange rate system was
announced. The new rate will be 4.3 Venezuelan Bolivars Fuertes per U.S. Dollar to apply to our
local currency denominated balances and transactions. Although our functional currency is the U.S.
Dollar in Venezuela, certain balances and transactions are denominated in local currency. We estimate the impact of this devaluation to be a loss of between $8 million to $10 million which will be recorded in the first
quarter of 2010. Going forward, although this devaluation will result in a
reduction in the U.S. Dollar reported amount of local currency denominated revenues and expenses,
we do not believe the impact will be material to our consolidated financial statements.
Foreign Currency Forward Contracts
At December 31, 2009, we had outstanding foreign currency forward contracts with notional
amounts aggregating $153 million to hedge exposure to currency fluctuations in various foreign
currencies. These contracts are designated and qualify as fair value hedging instruments. Based
on quoted market prices as of December 31, 2009 for contracts with similar terms and maturity
dates, we recorded a loss of $1 million to adjust these foreign currency forward contracts to their
fair market value. This loss offsets designated foreign currency exchange gains resulting from the
underlying exposures and is included in MG&A expenses in the consolidated statement of operations.
At December 31, 2008, we had outstanding foreign currency forward contracts with notional
amounts aggregating $125 million to hedge exposure to currency fluctuations in various foreign
currencies. These contracts are designated and qualify as fair value hedging instruments. Based
on quoted market prices as of December 31, 2008 for contracts with similar terms and maturity
dates, we recorded a loss of $1 million to adjust these foreign currency forward contracts to their
fair market value. This loss offsets designated foreign currency exchange gains resulting from the
underlying exposures and is included in MG&A expenses in the consolidated statement of operations.
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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, 2009. The conclusion of our principal
executive officer and principal financial officer is based on the recognition that there are
inherent limitations in all systems of internal control. Because of the inherent limitations of
internal control over financial reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented
or detected on a timely basis. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Deloitte & Touche LLP, the Companys independent registered public accounting firm, has issued
an attestation report on the effectiveness of the Companys internal control over financial
reporting.
/s/ CHAD C. DEATON
|
/s/ PETER A. RAGAUSS | /s/ ALAN J. KEIFER | ||
Chad C. Deaton
|
Peter A. Ragauss | Alan J. Keifer | ||
Chairman, President and
|
Senior Vice President and | Vice President and | ||
Chief Executive Officer
|
Chief Financial Officer | Controller |
Houston, Texas
February 25, 2010
February 25, 2010
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Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
Houston, Texas
We have audited the internal control over financial reporting of Baker Hughes Incorporated and
subsidiaries (the Company) as of December 31, 2009, based on criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A companys internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including
the possibility of collusion or improper management override of controls, material misstatements
due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2009, 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, 2009 of the Company and our report dated
February 25, 2010 expressed an unqualified opinion on those financial statements and financial
statement schedule.
/s/DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2010
February 25, 2010
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Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
Houston, Texas
We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and
subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated
statements of operations, stockholders equity, and cash flows for each of the three years in the
period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2009, 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.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Companys internal control over financial reporting as of
December 31, 2009, based on the criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 25, 2010 expressed an unqualified opinion on the Companys internal control over financial
reporting.
/s/DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2010
February 25, 2010
43
Table of Contents
Baker Hughes Incorporated
Consolidated Statements of Operations
(In millions, except per share amounts)
Consolidated Statements of Operations
(In millions, except per share amounts)
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Revenues: |
||||||||||||
Sales |
$ | 4,809 | $ | 5,734 | $ | 5,171 | ||||||
Services and rentals |
4,855 | 6,130 | 5,257 | |||||||||
Total revenues |
9,664 | 11,864 | 10,428 | |||||||||
Costs and expenses: |
||||||||||||
Cost of sales |
3,858 | 4,081 | 3,517 | |||||||||
Cost of services and rentals |
3,539 | 3,873 | 3,328 | |||||||||
Research and engineering |
397 | 426 | 372 | |||||||||
Marketing, general and administrative |
1,120 | 1,046 | 933 | |||||||||
Acquisition-related costs |
18 | | | |||||||||
Litigation settlement |
| 62 | | |||||||||
Total costs and expenses |
8,932 | 9,488 | 8,150 | |||||||||
Operating income |
732 | 2,376 | 2,278 | |||||||||
Equity in income of affiliates |
| 2 | 1 | |||||||||
Gain on sale of product line |
| 28 | | |||||||||
Gain (loss) on investments |
4 | (25 | ) | | ||||||||
Interest expense |
(131 | ) | (89 | ) | (66 | ) | ||||||
Interest and dividend income |
6 | 27 | 44 | |||||||||
Income before income taxes |
611 | 2,319 | 2,257 | |||||||||
Income taxes |
(190 | ) | (684 | ) | (743 | ) | ||||||
Net income |
$ | 421 | $ | 1,635 | $ | 1,514 | ||||||
Basic earnings per share |
$ | 1.36 | $ | 5.32 | $ | 4.76 | ||||||
Diluted earnings per share |
$ | 1.36 | $ | 5.30 | $ | 4.73 |
See Notes to Consolidated Financial Statements
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Table of Contents
Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except par value)
Consolidated Balance Sheets
(In millions, except par value)
December 31, | ||||||||
2009 | 2008 | |||||||
ASSETS |
||||||||
Current Assets: |
||||||||
Cash and cash equivalents |
$ | 1,595 | $ | 1,955 | ||||
Accounts
receivable less allowance for doubtful accounts (2009 - $157; 2008 - $74) |
2,331 | 2,759 | ||||||
Inventories, net |
1,836 | 2,021 | ||||||
Deferred income taxes |
268 | 231 | ||||||
Other current assets |
195 | 179 | ||||||
Total current assets |
6,225 | 7,145 | ||||||
Property, plant and equipment less accumulated depreciation
(2009 - $3,668; 2008 - $3,203) |
3,161 | 2,833 | ||||||
Goodwill |
1,418 | 1,389 | ||||||
Intangible assets, net |
195 | 198 | ||||||
Other assets |
440 | 296 | ||||||
Total assets |
$ | 11,439 | $ | 11,861 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current Liabilities: |
||||||||
Accounts payable |
$ | 821 | $ | 888 | ||||
Short-term borrowings and current portion of long-term debt |
15 | 558 | ||||||
Accrued employee compensation |
448 | 530 | ||||||
Income taxes payable |
95 | 272 | ||||||
Other accrued liabilities |
234 | 263 | ||||||
Total current liabilities |
1,613 | 2,511 | ||||||
Long-term debt |
1,785 | 1,775 | ||||||
Deferred income taxes and other tax liabilities |
309 | 384 | ||||||
Liabilities for pensions and other postretirement benefits |
379 | 317 | ||||||
Other liabilities |
69 | 67 | ||||||
Commitments and contingencies |
||||||||
Stockholders Equity: |
||||||||
Common stock, one dollar par value (shares authorized - 750;
issued and outstanding: 2009 - 312; 2008 - 309) |
312 | 309 | ||||||
Capital in excess of par value |
874 | 745 | ||||||
Retained earnings |
6,512 | 6,276 | ||||||
Accumulated other comprehensive loss |
(414 | ) | (523 | ) | ||||
Total stockholders equity |
7,284 | 6,807 | ||||||
Total liabilities and stockholders equity |
$ | 11,439 | $ | 11,861 | ||||
See Notes to Consolidated Financial Statements
45
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Baker Hughes Incorporated
Consolidated Statements of Stockholders Equity
(In millions, except per share amounts)
Consolidated Statements of Stockholders Equity
(In millions, except per share amounts)
Capital | Accumulated | |||||||||||||||||||
in Excess | Other | |||||||||||||||||||
Common | of | Retained | Comprehensive | |||||||||||||||||
Stock | Par Value | Earnings | Loss | Total | ||||||||||||||||
Balance, December 31, 2006 |
$ | 320 | $ | 1,600 | $ | 3,510 | $ | (187 | ) | $ | 5,243 | |||||||||
Adoption of ASC 360, Property, Plant and Equipment, net of tax of $(9) |
25 | 25 | ||||||||||||||||||
Adoption of ASC 740, Income Taxes |
(64 | ) | (64 | ) | ||||||||||||||||
Adjusted beginning balance January 1, 2007 |
$ | 320 | $ | 1,600 | $ | 3,471 | $ | (187 | ) | $ | 5,204 | |||||||||
Comprehensive income: |
||||||||||||||||||||
Net income |
1,514 | |||||||||||||||||||
Foreign currency translation adjustments |
72 | |||||||||||||||||||
Defined benefit pension plans, net of tax of $(37) |
71 | |||||||||||||||||||
Total comprehensive income |
1,657 | |||||||||||||||||||
Issuance of common stock, pursuant to employee stock plans |
2 | 66 | 68 | |||||||||||||||||
Tax benefit on stock plans |
19 | 19 | ||||||||||||||||||
Stock-based compensation |
46 | 46 | ||||||||||||||||||
Repurchase and retirement of common stock |
(6 | ) | (515 | ) | (521 | ) | ||||||||||||||
Cash dividends ($0.52 per share) |
(167 | ) | (167 | ) | ||||||||||||||||
Balance, December 31, 2007 |
$ | 316 | $ | 1,216 | $ | 4,818 | $ | (44 | ) | $ | 6,306 | |||||||||
Adoption of ASC 715, Compensation Retirement Benefits |
(4 | ) | (4 | ) | ||||||||||||||||
Adjusted beginning balance January 1, 2008 |
316 | 1,216 | 4,814 | (44 | ) | 6,302 | ||||||||||||||
Comprehensive income: |
||||||||||||||||||||
Net income |
1,635 | |||||||||||||||||||
Foreign currency translation adjustments |
(354 | ) | ||||||||||||||||||
Defined benefit pension plans, net of tax of $67 |
(125 | ) | ||||||||||||||||||
Total comprehensive income |
1,156 | |||||||||||||||||||
Issuance of common stock, pursuant to employee stock plans |
2 | 76 | 78 | |||||||||||||||||
Tax benefit on stock plans |
11 | 11 | ||||||||||||||||||
Stock-based compensation |
60 | 60 | ||||||||||||||||||
Repurchase and retirement of common stock |
(9 | ) | (618 | ) | (627 | ) | ||||||||||||||
Cash dividends ($0.56 per share) |
(173 | ) | (173 | ) | ||||||||||||||||
Balance, December 31, 2008 |
$ | 309 | $ | 745 | $ | 6,276 | $ | (523 | ) | $ | 6,807 | |||||||||
Comprehensive income: |
||||||||||||||||||||
Net income |
421 | |||||||||||||||||||
Foreign currency translation adjustments |
122 | |||||||||||||||||||
Defined benefit pension plans, net of tax of $2 |
(13 | ) | ||||||||||||||||||
Total comprehensive income |
530 | |||||||||||||||||||
Issuance of common stock, pursuant to employee stock plans |
3 | 43 | 46 | |||||||||||||||||
Tax provision on stock plans |
(2 | ) | (2 | ) | ||||||||||||||||
Stock-based compensation |
88 | 88 | ||||||||||||||||||
Cash dividends ($0.60 per share) |
(185 | ) | (185 | ) | ||||||||||||||||
Balance, December 31, 2009 |
$ | 312 | $ | 874 | $ | 6,512 | $ | (414 | ) | $ | 7,284 | |||||||||
See Notes to Consolidated Financial Statements
46
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Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions)
Consolidated Statements of Cash Flows
(In millions)
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Cash flows from operating activities: |
||||||||||||
Net income |
$ | 421 | $ | 1,635 | $ | 1,514 | ||||||
Adjustments to reconcile net income to net cash flows from operating activities: |
||||||||||||
Depreciation and amortization |
711 | 637 | 521 | |||||||||
(Gain) loss on investments |
(4 | ) | 25 | | ||||||||
Stock-based compensation costs |
88 | 60 | 51 | |||||||||
(Benefit) provision for deferred income taxes |
(256 | ) | (21 | ) | (4 | ) | ||||||
Gain on sale of product line |
| (28 | ) | | ||||||||
Gain on disposal of assets |
(64 | ) | (101 | ) | (79 | ) | ||||||
Provision for doubtful accounts |
94 | 31 | 22 | |||||||||
Changes in operating assets and liabilities: |
||||||||||||
Accounts receivable |
399 | (515 | ) | (309 | ) | |||||||
Inventories |
240 | (371 | ) | (142 | ) | |||||||
Accounts payable |
(89 | ) | 242 | 26 | ||||||||
Accrued employee compensation and other accrued liabilities |
(130 | ) | 90 | (139 | ) | |||||||
Income taxes payable |
(169 | ) | 76 | 129 | ||||||||
Income taxes paid on sale of interest in affiliate |
| | (125 | ) | ||||||||
Liabilities for pensions and other postretirement benefits and other liabilities |
13 | (38 | ) | (4 | ) | |||||||
Other |
(15 | ) | (108 | ) | 14 | |||||||
Net cash flows from operations |
1,239 | 1,614 | 1,475 | |||||||||
Cash flows from investing activities: |
||||||||||||
Expenditures for capital assets |
(1,086 | ) | (1,303 | ) | (1,127 | ) | ||||||
Proceeds from disposal of property, plant and equipment |
163 | 222 | 179 | |||||||||
Proceeds from sale of businesses and interests in affiliates |
| 31 | 10 | |||||||||
Acquisition of businesses, net of cash acquired |
(58 | ) | (120 | ) | | |||||||
Proceeds from sale of investments |
15 | | | |||||||||
Purchase of short-term investments |
| | (2,521 | ) | ||||||||
Proceeds from maturities of short-term investments |
| | 2,839 | |||||||||
Net cash flows from investing activities |
(966 | ) | (1,170 | ) | (620 | ) | ||||||
Cash flows from financing activities: |
||||||||||||
Net (repayments) borrowings of commercial paper and other short-term debt |
(16 | ) | 15 | 14 | ||||||||
Repayment of long-term debt |
(525 | ) | | | ||||||||
Proceeds from issuance of long-term debt |
| 1,235 | | |||||||||
Proceeds from issuance of common stock |
51 | 87 | 67 | |||||||||
Repurchase of common stock |
| (627 | ) | (521 | ) | |||||||
Dividends |
(185 | ) | (173 | ) | (167 | ) | ||||||
Excess tax benefits from stock-based compensation |
| 4 | 14 | |||||||||
Net cash flows from financing activities |
(675 | ) | 541 | (593 | ) | |||||||
Effect of foreign exchange rate changes on cash |
42 | (84 | ) | 42 | ||||||||
(Decrease) increase in cash and cash equivalents |
(360 | ) | 901 | 304 | ||||||||
Cash and cash equivalents, beginning of year |
1,955 | 1,054 | 750 | |||||||||
Cash and cash equivalents, end of year |
$ | 1,595 | $ | 1,955 | $ | 1,054 | ||||||
Supplemental cash flows disclosures: |
||||||||||||
Income taxes paid |
$ | 604 | $ | 621 | $ | 717 | ||||||
Interest paid |
$ | 154 | $ | 86 | $ | 76 | ||||||
Supplemental disclosure of noncash investing activities: |
||||||||||||
Capital expenditures included in accounts payable |
$ | 29 | $ | 43 | $ | 40 |
See Notes to Consolidated Financial Statements
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements
Notes to Consolidated Financial Statements
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Baker Hughes Incorporated (Baker Hughes) is engaged in the oilfield services industry. We
are a major supplier of wellbore related products and technology services and systems and provide
products and services for drilling, formation evaluation, completion and production, and reservoir
technology and consulting to the worldwide oil and natural gas industry.
Basis of Presentation
The consolidated financial statements include the accounts of Baker Hughes and all majority
owned subsidiaries (Company, we, our or us). Investments over which we have the ability to
exercise significant influence over operating and financial policies, but do not hold a controlling
interest, are accounted for using the equity method of accounting. All significant intercompany
accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated
Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and
shares, respectively, unless otherwise indicated.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and judgments that
affect the reported amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. We base our estimates and judgments on historical experience
and on various other assumptions and information that are believed to be reasonable under the
circumstances. Estimates and assumptions about future events and their effects cannot be perceived
with certainty and, accordingly, these estimates may change as new events occur, as more experience
is acquired, as additional information is obtained and as our operating environment changes. While
we believe that the estimates and assumptions used in the preparation of the consolidated financial
statements are appropriate, actual results could differ from those estimates. Estimates are used
for, but are not limited to, determining the following: allowance for doubtful accounts and
inventory valuation reserves, recoverability of long-lived assets, useful lives used in
depreciation and amortization, income taxes and related valuation allowances and insurance,
environmental, legal, pensions and postretirement benefit obligations and stock-based compensation.
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. In certain situations, revenue is generated from transactions that may
include multiple products and services under one contract or agreement. Revenue from these
arrangements is recognized as each item or service is delivered based on their relative fair value.
Cost of Sales and Cost of Services and Rentals
Cost of sales and cost of services and rentals include material, labor, selling and field
service costs, and overhead costs associated with the manufacture and distribution of our products
for sale or rental. Distribution costs include freight costs, purchasing and receiving costs,
warehousing costs and other costs of our distribution network.
Research and Engineering
Research and engineering expenses include costs associated with the research and development
of new products and services and costs associated with sustaining engineering of existing products
and services. These costs are expensed as incurred and include research and development costs for
new products and services of $231 million, $263 million and $234 million for the year ended
December 31, 2009, 2008 and 2007, respectively.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Marketing, General and Administrative
Marketing, general and administrative (MG&A) expenses include all advertising and marketing
efforts, business development costs, and other general and administrative costs not directly
associated with the manufacture and distribution of our products for sale or rental and the
employee related costs associated with these functions. MG&A expenses also include gains and
losses from foreign currency transactions.
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less at
the time of purchase to be cash equivalents.
Investments
Prior to September 2007, we invested in auction rate securities, which are variable-rate debt
securities. We limited our investments in auction rate securities (ARS) to non mortgage-backed
securities that, at the time of the initial investment, carried an AAA (or equivalent) rating from
a recognized rating agency. During 2009, we sold all ARS investments and recorded a gain of $4
million. During 2008, we recorded an impairment loss of $25 million on these investments.
Inventories
Inventories are stated at the lower of cost or market. Cost is determined using the first-in,
first-out (FIFO) method or the average cost method, which approximates FIFO, and includes the
cost of materials, labor and manufacturing overhead.
Property, Plant and Equipment and Accumulated Depreciation
Property, plant and equipment (PP&E) is stated at cost less accumulated depreciation, which
is generally provided by using the straight-line method over the estimated useful lives of the
individual assets. Significant improvements and betterments are capitalized if they extend the
useful life of the asset. We manufacture a substantial portion of our rental tools and equipment
and the cost of these items, which includes direct and indirect manufacturing costs, are
capitalized and carried in inventory until the tool is completed. Once the tool has been
completed, the cost of the tool is reflected in capital expenditures and the tool is classified as
rental tools and equipment in PP&E. Maintenance and repairs are charged to expense as incurred.
The capitalized costs of computer software developed or purchased for internal use are classified
in machinery and equipment in PP&E.
In 2006, the Financial Accounting Standards Board (FASB) issued an update to Accounting
Standards Codification (ASC) 360, Property, Plant and Equipment, which prohibits the use of the
accrue-in-advance method of accounting for planned major maintenance and repair activities. We
adopted this update on January 1, 2007, to change our method of accounting for repairs and
maintenance activities on certain rental tools from the accrue-in-advance method to the direct
expense method. The adoption resulted in an increase of $25 million to beginning retained earnings
as of January 1, 2007.
Asset Retirement Obligations
Legal obligations associated with the retirement of long-lived assets are to be recognized at
their fair value at the time that the obligations are incurred. Upon initial recognition of a
liability, that cost is capitalized as part of the related long-lived asset and depreciated on a
straight-line basis over the remaining estimated useful life of the related asset. Accretion
expense in connection with the discounted liability is also recognized over the remaining useful
life of the related asset. Asset retirement obligations were $18 million and $17 million at
December 31, 2009 and 2008, respectively.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Goodwill, Intangible Assets and Amortization
Goodwill and intangible assets with indefinite lives are not amortized. Intangible assets
with finite useful lives are amortized on a basis that reflects the pattern in which the economic
benefits of the intangible assets are realized, which is generally on a straight-line basis over
the assets estimated useful life.
Impairment of Long-Lived Assets
We review PP&E, intangible assets and certain other assets for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be recoverable. The
determination of recoverability is made based upon the estimated undiscounted future net cash
flows, excluding interest expense. The amount of impairment loss, if any, is determined by
comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value
of the related assets.
We perform an annual impairment test of goodwill for each of our reporting units as of October
1, or more frequently if circumstances indicate an impairment may exist. Our reporting units are
based on our organizational and reporting structure. Corporate and other assets and liabilities
are allocated to the reporting units to the extent that they relate to the operations of those
reporting units in determining their carrying amount. The determination of impairment is made by
comparing the carrying amount with its fair value, which is calculated using a combination of a
market and discounted cash flow approach.
Income Taxes
We use the liability method for determining our income taxes, under which current and deferred
tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this
method, the amounts of deferred tax liabilities and assets at the end of each period are determined
using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax
benefits are recognized to the extent that realization of such benefits is more likely than not.
Deferred income taxes are provided for the estimated income tax effect of temporary
differences between financial and tax bases in assets and liabilities. Deferred tax assets are
also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax
assets is established when it is more likely than not that some portion or all of the deferred tax
assets will not be realized.
We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations
outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We
do provide for the U.S. and additional non-U.S. taxes on earnings anticipated to be repatriated
from our non-U.S. subsidiaries.
We operate in more than 90 countries under many legal forms. As a result, we are subject to
the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and
treaties among these governments. Our operations in these different jurisdictions are taxed on
various bases: actual income before taxes, deemed profits (which are generally determined using a
percentage of revenues rather than profits) and withholding taxes based on revenue. Determination
of taxable income in any jurisdiction requires the interpretation of the related tax laws and
regulations and the use of estimates and assumptions regarding significant future events, such as
the amount, timing and character of deductions, permissible revenue recognition methods under the
tax law and the sources and character of income and tax credits. Changes in tax laws, regulations,
agreements and treaties, foreign currency exchange restrictions or our level of operations or
profitability in each tax jurisdiction could have an impact upon the amount of income taxes that we
provide during any given year.
Our tax filings for various periods are subjected to audit by tax authorities in most
jurisdictions where we conduct business. These audits may result in assessments of additional
taxes that are resolved with the authorities or through the courts. We believe that these
assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax
law. We have received tax assessments from various tax authorities and are currently at varying
stages of appeals and/or litigation regarding these matters. We have provided for the amounts we
believe will ultimately result from these proceedings. We believe we have substantial defenses to
the questions being raised and will pursue all legal remedies should an unfavorable outcome result.
However, resolution of these matters involves uncertainties and there are no assurances that the
outcomes will be favorable. We provide for uncertain tax positions pursuant to ASC 740, Income
Taxes.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
In July 2006, the FASB issued new guidance for accounting for uncertain tax positions which
provides that a tax benefit from an uncertain tax position may be recognized when it is more likely
than not that the position will be sustained upon examination, including resolutions of any related
appeals or litigation processes, based on the technical merits. The interpretation also provides
guidance on measurement, derecognition, classification, interest and penalties, accounting in
interim periods, disclosure and transition. We adopted the provisions effective January 1, 2007,
pursuant to which we recognized a $78 million increase in the gross liability for unrecognized tax
benefits, a $14 million increase in non-current tax receivables, and a net decrease to beginning
retained earnings of $64 million.
Product Warranties
We sell certain products with a product warranty that provides that customers can return a
defective product during a specified warranty period following the purchase in exchange for a
replacement product, repair at no cost to the customer or the issuance of a credit to the customer.
We accrue amounts for estimated warranty claims based upon current and historical product sales
data, warranty costs incurred and any other related information known to us. Our product warranty
liability was $11 million and $8 million at December 31, 2009 and 2008, respectively.
Environmental Matters
Estimated remediation costs are accrued using currently available facts, existing
environmental permits, technology and presently enacted laws and regulations. For sites where we
are primarily responsible for the remediation, our cost estimates are developed based on internal
evaluations and are not discounted. Accruals are recorded when it is probable that we will be
obligated to pay for environmental site evaluation, remediation or related activities, and such
costs can be reasonably estimated. If the obligation can only be estimated within a range, we
accrue the minimum amount in the range. Accruals are recorded even if significant uncertainties
exist over the ultimate cost of the remediation. As additional or more accurate information
becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental
compliance costs, such as obtaining environmental permits, installation of pollution control
equipment and waste disposal, are expensed as incurred. Where we have been identified as a
potentially responsible party in a United States federal or state Superfund site, we accrue our
share of the estimated remediation costs of the site. This share is based on the ratio of the
estimated volume of waste we contributed to the site to the total volume of waste disposed at the
site.
Foreign Currency
A number of our significant foreign subsidiaries have designated the local currency as their
functional currency and, as such, gains and losses resulting from balance sheet translation of
foreign operations are included as a separate component of accumulated other comprehensive loss
within stockholders equity. Gains and losses from foreign currency transactions, such as those
resulting from the settlement of receivables or payables in the non-functional currency, are
included in MG&A expenses in the consolidated statements of operations as incurred. For those
foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and
losses resulting from balance sheet remeasurement of foreign operations are also included in MG&A
expense in the consolidated statements of operations as incurred.
Derivative Financial Instruments
We monitor our exposure to various business risks including commodity prices, foreign currency
exchange rates and interest rates and occasionally use derivative financial instruments to manage
these risks. Our policies do not permit the use of derivative financial instruments for
speculative purposes. We use foreign currency forward contracts to hedge certain firm commitments
and transactions denominated in foreign currencies. We use interest rate swaps to manage interest
rate risk.
At the inception of any new derivative, we designate the derivative as a hedge as that term is
defined in ASC 815, Derivatives and Hedging 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.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
New Accounting Standards and Accounting Standards Updates
In June 2009, the FASB issued ASC 105, Generally Accepted Accounting Principles. The ASC
identifies itself as the source of authoritative accounting principles recognized by the FASB to be
applied by nongovernmental entities in the preparation of financial statements in conformity with
generally accepted accounting principles in the United States. Rules and interpretive releases of
the SEC under authority of federal securities laws are also sources of authoritative GAAP. The ASC
does not change GAAP, but is intended to simplify user access to all authoritative GAAP by
providing all the authoritative literature related to a particular topic in one place. This
statement is effective for financial statements issued for interim and annual periods ending after
September 15, 2009. We have included references to authoritative accounting literature in
accordance with the Codification. There are no other changes to the content of the Companys
financial statements or disclosures as a result of the adoption.
In October 2009, the FASB issued an update to ASC 605, Revenue Recognition Multiple
Deliverable Revenue Arrangements. This ASU addresses accounting for multiple-deliverable
arrangements to enable vendors to account for deliverables separately. The provision establishes a
selling price hierarchy for determining the selling price of a deliverable. This update requires
expanded disclosures for multiple deliverable revenue arrangements. The ASU will be effective for
revenue arrangements entered into or materially modified beginning on or after June 15, 2010. We
have not determined the impact, if any, on our consolidated financial statements.
In September 2006, FASB issued ASC 820, Fair Value Measurements and Disclosures, 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. On January 1, 2008, we adopted the provisions of this ASC related to financial
assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a
recurring basis and on January 1, 2009, we adopted the provisions related to nonfinancial assets
and liabilities that are not required or permitted to be measured at fair value on a recurring
basis. There was no material impact to our consolidated financial statements related to these
adoptions. Additionally, in April 2009, the FASB issued the following three accounting standards
updates: (i) ASC 820, Determining Fair Value When the Volume and Level of Activity for the Asset
or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, (ii)
ASC 320, Recognition and Presentation of Other-Than-Temporary Impairments, and (iii) ASC 825,
Interim Disclosures about Fair Value of Financial Instruments, which collectively provide
additional guidance and require additional disclosure regarding determining and reporting fair
values for certain assets and liabilities. We adopted the three accounting standards updates in
the second quarter of 2009 with no material impact to our consolidated financial statements. In
September 2009, the FASB issued an update to ASC 820, Fair Value Measurements and Disclosures -
Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). The
ASU provides a practical means for measuring the fair value of investments in certain entities that
calculate net asset value per share. The ASU is effective for the first reporting period ending
after December 15, 2009. We adopted the provisions and disclosure requirements of this ASU in
December 2009 with no material impact to our consolidated financial statements.
In December 2007, the FASB issued an update to ASC 810, Consolidation, to establish accounting
and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation
of a subsidiary in an effort to improve the relevance, comparability and transparency of the
financial information that a reporting entity provides. On January 1, 2009, we adopted this
statement with no change to our consolidated financial statements as amounts are immaterial.
In December 2007, the FASB issued an update to ASC 805, Business Combinations, to establish
principles and requirements for the recognition and measurement of assets, liabilities and
goodwill, and requires that most transaction and restructuring costs related to the acquisition be
expensed. We have applied the provisions of this ASC for business combinations with an acquisition
date on or after January 1, 2009.
In March 2008, the FASB issued an update to ASC 815, Disclosures about Derivative Instruments
and Hedging Activities, to require qualitative disclosures about objectives and strategies for
using derivatives and quantitative data about the fair value of and gains and losses on derivative
contracts. We adopted the new disclosure requirements in the first quarter of 2009.
In June 2008, the FASB issued an update to ASC 260, Determining Whether Instruments Granted in
Share-Based Payment Transactions Are Participating Securities, to clarify that all unvested
share-based payments that contain rights to non-forfeitable dividends are participating securities
and shall be included in the computation of both basic and diluted earnings per share. On January
1, 2009, we adopted this ASC and have not applied the provisions to prior year quarters as the
impact is immaterial.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
In December 2008, the FASB issued an update to ASC 715, Employers Disclosures about
Postretirement Benefit Plan Assets, to require the disclosures of investment policies and
strategies, major categories of plan assets, fair value measurement of plan assets and significant
concentration of credit risks. We adopted the new disclosure requirements in the fourth quarter of
2009. See Note 14 of the Notes to Consolidated Financial Statements in Item 8 herein for further
information on the impact of this standard.
NOTE 2. PENDING MERGER WITH BJ SERVICES
On August 30, 2009, the Company and its subsidiary and BJ Services Company (BJ Services)
entered into a merger agreement (the Merger Agreement) pursuant to which the Company will acquire
100% of the outstanding common stock of BJ Services in exchange for newly issued shares of the
Companys common stock and cash. BJ Services is a leading provider of pressure pumping and
oilfield services. The Merger Agreement and the merger have been approved by the Board of
Directors of both the Company and BJ Services. Consummation of the merger is subject to the
approval of the stockholders of the Company and BJ Services stockholders at special meetings
scheduled on March 19, 2010 subject to adjournment or postponement, regulatory approvals, and the
satisfaction or waiver of various other conditions as more fully described in the Merger Agreement.
Subject to receipt of all required approvals, it is anticipated that closing of the merger
will occur in March of 2010. Under the terms of the Merger Agreement, each share of BJ
Services common stock will be converted into the right to receive 0.40035 shares of the Companys
common stock and $2.69 in cash. Baker Hughes has estimated the total consideration expected to be
issued and paid in the merger to be approximately $6.4 billion, consisting of approximately $0.8
billion to be paid in cash and approximately $5.6 billion to be paid through the issuance of
approximately 118 million shares of Baker Hughes common stock valued at the February 11, 2010
closing share price of $46.68 per share. The value of the merger consideration will fluctuate
based upon changes in the price of shares of Baker Hughes common stock and the number of BJ
Services common shares and options outstanding at the closing date.
NOTE 3. GAIN ON SALE OF PRODUCT LINE
In February 2008, we sold the assets associated with the Completion and Production segments
Surface Safety Systems (SSS) product line and received cash proceeds of $31 million. The SSS
assets sold included hydraulic and pneumatic actuators, bonnet assemblies and control systems. We
recorded a pre-tax gain of $28 million ($18 million after-tax) in 2008.
NOTE 4. STOCK-BASED COMPENSATION
Stock-based compensation cost is measured at the date of grant, based on the calculated fair
value of the award, and is recognized as expense over the employees service period, which is
generally the vesting period of the equity grant. Additionally, compensation cost is recognized
based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated
forfeitures based on historical forfeiture rates. Forfeitures are estimated at the time of grant
and revised, if necessary, in subsequent periods to reflect actual forfeitures.
The following table summarizes stock-based compensation costs for the years ended December 31,
2009, 2008 and 2007. There were no stock-based compensation costs capitalized as the amounts were
not material.
2009 | 2008 | 2007 | ||||||||||
Stock-based compensation costs |
$ | 88 | $ | 60 | $ | 51 | ||||||
Tax benefit |
(15 | ) | (11 | ) | (11 | ) | ||||||
Stock-based compensation costs, net of tax |
$ | 73 | $ | 49 | $ | 40 | ||||||
For our stock options and restricted stock awards and units, we currently have 17 million
shares authorized for issuance and as of December 31, 2009, approximately 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
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
vesting upon the employees retirement; therefore, the service period is reduced for employees that
are or will become retirement eligible during the vesting period and, accordingly, the recognition
of compensation expense for these employees is accelerated. Compensation cost related to stock
options is recognized on a straight-line basis over the vesting or service period and is net of
forfeitures.
The fair value of each stock option granted is estimated using the Black-Scholes option
pricing model. The following table presents the weighted average assumptions used in the option
pricing model for options granted. The expected life of the options represents the period of time
the options are expected to be outstanding. The expected life is based on our historical exercise
trends and post-vest termination data incorporated into a forward-looking stock price model. 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.
2009 | 2008 | 2007 | ||||||||||
Expected life (years) |
6.0 | 5.5 | 5.1 | |||||||||
Risk-free interest rate |
2.6 | % | 3.1 | % | 4.8 | % | ||||||
Volatility |
41.2 | % | 31.4 | % | 28.6 | % | ||||||
Dividend yield |
1.8 | % | 0.8 | % | 0.7 | % | ||||||
Weighted average fair value per share at grant date |
$ | 12.66 | $ | 23.64 | $ | 24.20 |
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, 2008 |
3,470 | $ | 59.92 | |||||
Granted |
2,311 | 35.03 | ||||||
Exercised |
(40 | ) | 29.16 | |||||
Forfeited |
(55 | ) | 49.18 | |||||
Expired |
(10 | ) | 36.77 | |||||
Outstanding at December 31, 2009 |
5,676 | $ | 50.16 | |||||
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
2009, 2008 and 2007 was $0.4 million, $13 million and $73 million, respectively. The income tax
benefit realized from stock options exercised was $0.1 million, $7 million and $19 million in 2009,
2008 and 2007, respectively.
The total fair value of options vested in 2009, 2008 and 2007 was $17 million, $17 million and
$20 million, respectively. As of December 31, 2009, there was $15 million of total unrecognized
compensation cost related to nonvested stock options which is expected to be recognized over a
weighted average period of two years.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
The following table summarizes information about stock options outstanding as of December 31,
2009 (in thousands, except per option prices and remaining life):
Outstanding | Exercisable | |||||||||||||||||||||||||||||||
Weighted | Weighted | |||||||||||||||||||||||||||||||
Average | Weighted | Average | Weighted | |||||||||||||||||||||||||||||
Remaining | Average | Remaining | Average | |||||||||||||||||||||||||||||
Contractual | Exercise | Contractual | Exercise | |||||||||||||||||||||||||||||
Number of | Life | Price Per | Number of | Life | Price Per | |||||||||||||||||||||||||||
Range of Exercise Prices | Options | (In years) | Option | Options | (In years) | Option | ||||||||||||||||||||||||||
$ |
14.79 | | $ | 16.78 | 3 | 3.7 | $ | 15.84 | 3 | 3.7 | $ | 15.84 | ||||||||||||||||||||
22.88 | | 33.32 | 1,286 | 7.6 | 29.35 | 377 | 4.0 | 29.73 | ||||||||||||||||||||||||
34.45 | | 46.48 | 2,146 | 7.5 | 39.77 | 860 | 4.4 | 40.22 | ||||||||||||||||||||||||
56.21 | | 82.28 | 2,218 | 7.1 | 71.94 | 1,639 | 6.7 | 71.20 | ||||||||||||||||||||||||
86.50 | | 86.50 | 23 | 8.6 | 86.50 | 8 | 8.6 | 86.50 | ||||||||||||||||||||||||
Total |
5,676 | 7.4 | $ | 50.16 | 2,887 | 5.7 | $ | 56.54 | ||||||||||||||||||||||||
The aggregate intrinsic value of stock options outstanding at December 31, 2009 was $17
million, $5 million of which relates to options vested and exercisable. The intrinsic value for
stock options outstanding is calculated as the amount by which the quoted price of $40.48 of our
common stock as of the end of 2009 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.
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, 2008 |
902 | $ | 69.63 | 325 | $ | 74.74 | ||||||||||
Granted |
1,091 | 31.18 | 427 | 31.54 | ||||||||||||
Vested |
(412 | ) | 68.28 | (116 | ) | 73.41 | ||||||||||
Forfeited |
(65 | ) | 44.61 | (42 | ) | 45.56 | ||||||||||
Nonvested balance at December 31, 2009 |
1,516 | $ | 43.40 | 594 | $ | 46.01 | ||||||||||
The weighted average grant date fair value per share for RSAs in 2009, 2008 and 2007 was
$31.18, $72.82 and $68.59, respectively. The weighted average grant date fair value per unit for
RSUs in 2009, 2008 and 2007 was $31.54, $75.96 and $68.54, respectively.
The total fair value of RSAs and RSUs vested in 2009, 2008 and 2007 was $18 million, $30
million and $16 million, respectively. As of December 31, 2009, there was $38 million and $18
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 two years.
Employee Stock Purchase Plan
In 2009, the Employee Stock Purchase Plan (ESPP) allowed eligible employees to elect to
contribute on an after-tax basis between 1% and 10% of their annual pay to purchase our common
stock; provided, however, an employee may not contribute more
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
than $25,000 annually to the plan pursuant to Internal Revenue Service restrictions. Shares
are purchased at a 15% discount of the fair market value of our common stock on January
1 or December 31, whichever is lower.
Effective January 1, 2010, the ESPP will provide for shares to be purchased: (i) on June
30 of each year at a 15% discount of the fair market value of our common stock on
January 1 or June 30, whichever is lower, and (ii) on December
31 of each year at a 15% discount of fair market value of our common stock on July
1 or December 31, whichever is lower. Also effective January 1, 2010, an
employee may not contribute more than $5,000 in either of the six-month measurement periods
described above or $10,000 annually. All other terms and conditions of the ESPP remain in effect.
We currently have 22.5 million shares authorized for issuance under the ESPP, and at December
31, 2009, there were 7.2 million shares reserved for future issuance under the ESPP. Compensation
expense determined under ASC 718, Compensation Stock Compensation for the year ended December 31,
2009 was calculated using the Black-Scholes option pricing model with the following assumptions:
2009 | 2008 | 2007 | ||||||||||
Expected life (years) |
1.0 | 1.0 | 1.0 | |||||||||
Risk-free interest rate |
0.3 | % | 3.2 | % | 4.9 | % | ||||||
Volatility |
69.5 | % | 32.8 | % | 30.5 | % | ||||||
Dividend yield |
1.9 | % | 0.6 | % | 0.7 | % | ||||||
Fair value per share of 15% cash discount |
$ | 4.81 | $ | 10.01 | $ | 9.07 | ||||||
Fair value per share of look-back provision |
8.44 | 11.44 | 10.39 | |||||||||
Total weighted average fair value per share at grant date |
$ | 13.25 | $ | 21.45 | $ | 19.46 | ||||||
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. INCOME TAXES
The provision for income taxes on income is comprised of the following for the years ended
December 31:
2009 | 2008 | 2007 | ||||||||||
Current: |
||||||||||||
United States |
$ | 65 | $ | 292 | $ | 366 | ||||||
Foreign |
381 | 413 | 381 | |||||||||
Total current |
446 | 705 | 747 | |||||||||
Deferred: |
||||||||||||
United States |
(210 | ) | (14 | ) | 19 | |||||||
Foreign |
(46 | ) | (7 | ) | (23 | ) | ||||||
Total deferred |
(256 | ) | (21 | ) | (4 | ) | ||||||
Provision for income taxes |
$ | 190 | $ | 684 | $ | 743 | ||||||
The geographic sources of income before income taxes are as follows for the years ended
December 31:
2009 | 2008 | 2007 | ||||||||||
United States |
$ | (18 | ) | $ | 795 | $ | 877 | |||||
Foreign |
629 | 1,524 | 1,380 | |||||||||
Income before income taxes |
$ | 611 | $ | 2,319 | $ | 2,257 | ||||||
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
The provision for income taxes differs from the amount computed by applying the U.S. statutory
income tax rate to income before income taxes for the reasons set forth below for the years ended
December 31:
2009 | 2008 | 2007 | ||||||||||
Statutory income tax at 35% |
$ | 214 | $ | 812 | $ | 790 | ||||||
Effect of foreign operations |
(61 | ) | (134 | ) | (84 | ) | ||||||
Net tax charge (benefit) related to foreign losses |
38 | 3 | (1 | ) | ||||||||
State income taxes net of U.S. tax benefit |
6 | 19 | 18 | |||||||||
Other net |
(7 | ) | (16 | ) | 20 | |||||||
Provision for income taxes |
$ | 190 | $ | 684 | $ | 743 | ||||||
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:
2009 | 2008 | |||||||
Deferred tax assets: |
||||||||
Receivables |
$ | 29 | $ | 9 | ||||
Inventory |
233 | 206 | ||||||
Property |
51 | 71 | ||||||
Employee benefits |
131 | 124 | ||||||
Other accrued expenses |
49 | 35 | ||||||
Operating loss carryforwards |
76 | 36 | ||||||
Tax credit carryforwards |
171 | 54 | ||||||
Capitalized research and development costs |
8 | 16 | ||||||
Other |
63 | 55 | ||||||
Subtotal |
811 | 606 | ||||||
Valuation allowances |
(142 | ) | (77 | ) | ||||
Total |
669 | 529 | ||||||
Deferred tax liabilities: |
||||||||
Goodwill |
142 | 139 | ||||||
Undistributed earnings of foreign subsidiaries |
64 | 124 | ||||||
Other |
43 | 45 | ||||||
Total |
249 | 308 | ||||||
Net deferred tax asset |
$ | 420 | $ | 221 | ||||
We record a valuation allowance when it is more likely than not that some portion or all of
the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets
depends on the ability to generate sufficient taxable income of the appropriate character in the
future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for
operating loss and foreign tax credit carryforwards in certain non-U.S. jurisdictions. Of the $65
million net increase in valuation allowance in 2009, $38 million represents net tax charges related
to foreign losses, $28 million pertains to a change in our ability to fully utilize deferred tax
assets in Venezuela offset by a $12 million reduction in valuation allowance related to deferred
tax assets in Brazil. The remaining $11 million net increase represents various items none of which
are individually significant. The operating loss carryforwards without a valuation allowance will
expire in varying amounts over the next twenty years.
We have provided for U.S. and additional foreign taxes for the anticipated repatriation of
certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our
foreign subsidiaries above the amount for which taxes have already been provided to be indefinitely
reinvested, as we have no intention to repatriate these earnings. As such, deferred income taxes
are not provided for temporary differences of approximately $2.3 billion, $2.2 billion and $1.6
billion as of December 31, 2009, 2008 and 2007, respectively, representing earnings of non-U.S.
subsidiaries intended to be permanently reinvested. These additional foreign earnings could become
subject to additional tax if remitted, or deemed remitted, as a dividend. Computation of the
potential deferred tax liability associated with these undistributed earnings and other basis
difference is not practicable.
At December 31, 2009, we had approximately $55 million of foreign tax credits which may be
carried forward indefinitely under applicable foreign law and $115 million of foreign tax credits
available to offset future payments of federal income taxes, expiring in
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
2018 and 2019. In addition, at December 31, 2009, we had approximately $1 million of state
tax credits expiring in varying amounts
between 2016 and 2021.
As of December 31, 2009, we had $339 million of tax liabilities for gross unrecognized tax
benefits, which includes liabilities for interest and penalties of $72 million and $17 million,
respectively. If we were to prevail on all uncertain tax positions, the net effect would be a
benefit to our effective tax rate of approximately $288 million. The remaining approximately $51
million, which is recorded as a deferred tax asset, represents tax benefits that would be received
in different taxing jurisdictions in the event that we did not prevail on all uncertain tax
positions.
We classify interest and penalties related to unrecognized tax benefits as income taxes in our
financial statements. For the year ended December 31, 2009, we recognized tax provision of $11
million for interest and penalties related to unrecognized tax benefits in the consolidated
statement of operations.
The following presents a rollforward of our unrecognized tax benefits and associated interest
and penalties included in the balance sheet.
Gross | ||||||||||||
Unrecognized | ||||||||||||
Tax Benefits, | ||||||||||||
Excluding | Total Gross | |||||||||||
Interest and | Interest and | Unrecognized | ||||||||||
Penalties | Penalties | Tax Benefits | ||||||||||
Balance at January 1, 2007 |
$ | 354 | $ | 69 | $ | 423 | ||||||
Increase in prior year tax positions |
3 | 21 | 24 | |||||||||
Increase in current year tax positions |
20 | 5 | 25 | |||||||||
Decrease related to settlements with
taxing authorities and lapse of statute of limitations |
(22 | ) | (5 | ) | (27 | ) | ||||||
Increase due to effects of foreign currency translation |
8 | 4 | 12 | |||||||||
Balance at January 1, 2008 |
363 | 94 | 457 | |||||||||
Increase/(decrease) in prior year tax positions |
(7 | ) | 10 | 3 | ||||||||
Increase in current year tax positions |
17 | 5 | 22 | |||||||||
Decrease related to settlements with taxing authorities |
(24 | ) | (10 | ) | (34 | ) | ||||||
Decrease related to lapse of statute of limitations |
(20 | ) | (17 | ) | (37 | ) | ||||||
Decrease due to effects of foreign currency translation |
(6 | ) | (4 | ) | (10 | ) | ||||||
Balance at January 1, 2009 |
323 | 78 | 401 | |||||||||
Increase/(decrease) in prior year tax positions |
(75 | ) | 10 | (65 | ) | |||||||
Increase in current year tax positions |
16 | 6 | 22 | |||||||||
Decrease related to settlements with taxing authorities |
(6 | ) | (2 | ) | (8 | ) | ||||||
Decrease related to lapse of statute of limitations |
(9 | ) | (4 | ) | (13 | ) | ||||||
Increase due to effects of foreign currency translation |
1 | 1 | 2 | |||||||||
Balance at December 31, 2009 |
$ | 250 | $ | 89 | $ | 339 | ||||||
It is expected that the amount of unrecognized tax benefits will change in the next 12
months due to expiring statutes, audit activity, tax payments, competent authority proceedings
related to transfer pricing, or final decisions in matters that are the subject of litigation in
various taxing jurisdictions in which we operate. At December 31, 2009, we had approximately $80
million of tax liabilities, net of $35 million of tax assets, related to uncertain tax positions,
each of which are individually insignificant, and each of which are reasonably possible of being
settled within the next twelve months primarily as the result of audit settlements or statute
expirations in several taxing jurisdictions.
At December 31, 2009, approximately $224 million of gross unrecognized tax benefits were
included in the non-current portion of our income tax liabilities, for which the settlement period
cannot be determined; however, it is not expected to be within the next 12 months.
We operate in over 90 countries and are subject to income taxes in most taxing jurisdictions
in which we operate. The following table summarizes the earliest tax years that remain subject to
examination by the major taxing jurisdictions in which we operate. These jurisdictions are those
we project to have the highest tax liability for 2010.
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Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Earliest Open Tax | Earliest Open Tax | |||||||||||
Jurisdiction | Period | Jurisdiction | Period | |||||||||
Canada |
1998 | Norway | 1999 | |||||||||
Germany |
2003 | United Kingdom | 2004 | |||||||||
Netherlands |
1999 | United States | 2002 |
NOTE 6. EARNINGS PER SHARE
On January 1, 2009, we adopted an update to ASC 260 which clarifies that all unvested
share-based payments that contain rights to non-forfeitable dividends are participating securities
and shall be included in the computation of both basic and diluted earnings per share. ASC 260 has
not been applied to any prior year as the impact is immaterial.
A reconciliation of the number of shares used for the basic and diluted EPS computations is as
follows for the years ended December 31:
2009 | 2008 | 2007 | ||||||||||
Weighted average common shares outstanding for basic EPS |
310 | 307 | 318 | |||||||||
Effect of dilutive securities stock plans |
1 | 2 | 2 | |||||||||
Adjusted weighted average common shares outstanding for diluted EPS |
311 | 309 | 320 | |||||||||
Future potentially dilutive shares excluded from diluted EPS: |
||||||||||||
Options with an exercise price greater than the average market
price for the period |
4 | 2 | 1 |
NOTE 7. INVENTORIES
Inventories, net of reserves of $297 million and $244 million in 2009 and 2008, respectively,
are comprised of the following at December 31:
2009 | 2008 | |||||||
Finished goods |
$ | 1,570 | $ | 1,693 | ||||
Work in process |
126 | 175 | ||||||
Raw materials |
140 | 153 | ||||||
Total |
$ | 1,836 | $ | 2,021 | ||||
NOTE 8. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment are comprised of the following at December 31:
Depreciation | ||||||||||||
Period | 2009 | 2008 | ||||||||||
Land |
$ | 81 | $ | 85 | ||||||||
Buildings and improvements |
1 - 30 years | 1,136 | 878 | |||||||||
Machinery and equipment |
1 - 20 years | 3,384 | 3,082 | |||||||||
Rental tools and equipment |
1 - 15 years | 2,228 | 1,991 | |||||||||
Subtotal |
6,829 | 6,036 | ||||||||||
Accumulated depreciation |
(3,668 | ) | (3,203 | ) | ||||||||
Total |
$ | 3,161 | $ | 2,833 | ||||||||
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
NOTE 9. GOODWILL AND INTANGIBLE ASSETS
The changes in the carrying amount of goodwill are detailed below by segment:
Drilling | Completion | |||||||||||
and | and | |||||||||||
Evaluation | Production | Total | ||||||||||
Balance as of December 31, 2007 |
$ | 914 | $ | 440 | $ | 1,354 | ||||||
Goodwill acquired during the period |
45 | | 45 | |||||||||
Purchase price and other adjustments |
9 | | 9 | |||||||||
Impact of foreign currency translation adjustments |
(17 | ) | (2 | ) | (19 | ) | ||||||
Balance as of December 31, 2008 |
951 | 438 | 1,389 | |||||||||
Goodwill acquired during the period |
9 | | 9 | |||||||||
Purchase price and other adjustments |
8 | 1 | 9 | |||||||||
Impact of foreign currency translation adjustments |
11 | | 11 | |||||||||
Balance as of December 31, 2009 |
$ | 979 | $ | 439 | $ | 1,418 | ||||||
We perform an annual impairment test of goodwill as of October 1 of every year. There were no
impairments of goodwill in 2009, 2008 or 2007 related to the annual impairment test.
Intangible assets are comprised of the following at December 31:
2009 | 2008 | |||||||||||||||||||||||
Gross | Gross | |||||||||||||||||||||||
Carrying | Accumulated | Carrying | Accumulated | |||||||||||||||||||||
Amount | Amortization | Net | Amount | Amortization | Net | |||||||||||||||||||
Technology-based |
$ | 277 | $ | (140 | ) | $ | 137 | $ | 256 | $ | (122 | ) | $ | 134 | ||||||||||
Contract-based |
13 | (9 | ) | 4 | 12 | (7 | ) | 5 | ||||||||||||||||
Marketing-related |
36 | (13 | ) | 23 | 33 | (6 | ) | 27 | ||||||||||||||||
Customer-based |
41 | (10 | ) | 31 | 37 | (5 | ) | 32 | ||||||||||||||||
Other |
1 | (1 | ) | | 1 | (1 | ) | | ||||||||||||||||
Total |
$ | 368 | $ | (173 | ) | $ | 195 | $ | 339 | $ | (141 | ) | $ | 198 | ||||||||||
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, 2009, 2008 and
2007 was $31 million, $20 million and $21 million, respectively. Estimated amortization expense
for each of the subsequent five fiscal years is expected to be as follows: 2010 $24 million; 2011
$19 million; 2012 $18 million; 2013 $17 million; and 2014 $16 million.
NOTE 10. FAIR VALUE OF CERTAIN FINANCIAL ASSETS AND LIABILITIES
We measure certain financial assets and liabilities at fair value. Fair value is defined as
the price that would be received to sell an asset or paid to transfer a liability (an exit price)
in an orderly transaction between market participants at the reporting date. We use the fair value
hierarchy that prioritizes the inputs used to measure fair value into three broad levels as
described below:
| Level 1: Quoted prices in active markets for identical assets or liabilities (these are observable market inputs). The fair value hierarchy gives the highest priority to Level 1 inputs. | ||
| Level 2: Observable prices that are based on inputs not quoted on active markets (includes quoted market prices for similar assets or identical or similar assets in markets in which there are few transactions, prices that are not current or vary substantially). | ||
| Level 3: Unobservable inputs that reflect the entitys own assumptions in pricing the asset or liability (used when little or no market data is available). |
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Financial assets and liabilities included in our financial statements and measured at fair
value as of December 31, 2009 and 2008 are classified based on the valuation hierarchy in the table
below:
Fair Value Measurement at | ||||||||||||||||
December 31, 2009 | ||||||||||||||||
Description | Total | Level 1 | Level 2 | Level 3 | ||||||||||||
Assets: |
||||||||||||||||
Non-qualified defined contribution plan assets |
$ | 146 | $ | 146 | $ | | $ | | ||||||||
Liabilities: |
||||||||||||||||
Non-qualified defined contribution plan liabilities |
$ | 146 | $ | 146 | $ | | $ | | ||||||||
Fair Value Measurement at | ||||||||||||||||
December 31, 2008 | ||||||||||||||||
Description | Total | Level 1 | Level 2 | Level 3 | ||||||||||||
Assets: |
||||||||||||||||
Auction rate securities |
$ | 11 | $ | | $ | | $ | 11 | ||||||||
Non-qualified defined contribution plan assets |
112 | 112 | | | ||||||||||||
Total assets at fair value |
$ | 123 | $ | 112 | $ | | $ | 11 | ||||||||
Liabilities: |
||||||||||||||||
Non-qualified defined contribution plan liabilities |
$ | 112 | $ | 112 | $ | | $ | | ||||||||
The following is a reconciliation of activity for the period for assets measured at fair value
based on significant unobservable inputs (Level 3).
Level 3 | ||||
Fair Value Measurements | ||||
Auction Rate Securities | ||||
Balance as of December 31, 2007 |
$ | 36 | ||
Total gains or (losses) realized and unrealized: |
||||
Included in earnings (or changes to net assets) |
(25 | ) | ||
Included in other comprehensive income |
| |||
Balance as of December 31, 2008 |
$ | 11 | ||
Total gains or (losses) realized and unrealized: |
||||
Included in earnings (or changes to net assets) |
4 | |||
Sales |
(15 | ) | ||
Included in other comprehensive income |
| |||
Balance as of December 31, 2009 |
$ | | ||
Auction Rate Securities
The Company owned auction rate securities (ARS) that were purchased in 2007 at an original
cost of $36 million. These ARS represented interests in three variable rate debt securities, which
are credit linked notes that generally combine low risk assets and credit default swaps (CDS) to
create a security that pays interest from the assets coupon payments and the periodic sale
proceeds of the CDS. In December 2009, we sold all ARS investments for $15 million and recorded a
gain of $4 million.
When estimating the fair value of the ARS investments we used Level 3 inputs. These inputs
were based on the underlying structure of each security and their collateral values, including
assessments of the credit quality, the default risk, the expected cash flows, the discount rates
and the overall capital market liquidity. Based on our ability and intent to hold such investments
for a period of time sufficient to allow for any anticipated recovery in the fair value, we had
classified all ARS as noncurrent investments up until the sale in December 2009.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Non-qualified Defined Contribution Plan Assets and Liabilities
We have a non-qualified defined contribution plan that provides basically the same benefit as
our Thrift Plan for certain non-U.S. employees who are not eligible to participate in the Thrift
Plan. In addition, we provide a non-qualified supplemental retirement plan for certain officers
and employees whose benefits under the Thrift Plan and/or U.S. defined benefit pension plan are
limited by federal tax law. The assets of both plans consist primarily of mutual funds and to a
lesser extent equity securities. We hold the assets of these plans under a grantor trust and have
recorded the assets along with the related deferred compensation liability at fair value. The
assets and liabilities were valued using Level 1 inputs at the reporting date and were based on
quoted market prices from various major stock exchanges.
NOTE 11. FINANCIAL INSTRUMENTS
Fair Value of Financial Instruments
Our financial instruments include cash and short-term investments, noncurrent investments in
auction rate securities, accounts receivable, accounts payable, debt, foreign currency forward
contracts, foreign currency option contracts and interest rate swaps. Except as described below,
the estimated fair value of such financial instruments at December 31, 2009 and 2008 approximates
their carrying value as reflected in our consolidated balance sheets. The fair value of our debt,
foreign currency forward contracts and interest rate swaps has been estimated based on quoted year
end market prices.
The estimated fair value of total debt at December 31, 2009 and 2008 was $2,126 million and
$2,471 million, respectively, which differs from the carrying amounts of $1,800 million and $2,333
million, respectively, included in our consolidated balance sheets.
Foreign Currency Forward Contracts
We conduct our business in over 90 countries around the world, and we are exposed to market
risks resulting from fluctuations in foreign currency exchange rates. A number of our significant
foreign subsidiaries have designated the local currency as their functional currency. We transact
in various foreign currencies and have established a program that primarily utilizes foreign
currency forward contracts to reduce the risks associated with the effects of certain foreign
currency exposures. Under this program, our strategy is to have gains or losses on the foreign
currency forward contracts mitigate the foreign currency transaction gains or losses to the extent
practical. These foreign currency exposures typically arise from changes in the value of assets
and liabilities which are denominated in currencies other than the functional currency. Our
foreign currency forward contracts generally settle within 90 days. We do not use these forward
contracts for trading or speculative purposes. We designate these forward contracts as fair value
hedging instruments pursuant to ASC 815, Derivatives and Hedging. Accordingly, we record the fair
value of these contracts as of the end of our reporting period to our consolidated balance sheet
with changes in fair value recorded in our consolidated statement of operations along with the
change in fair value of the hedged item.
At December 31, 2009 and 2008, we had outstanding foreign currency forward contracts with
notional amounts aggregating $153 million and $125 million, respectively, to hedge exposure to
currency fluctuations in various foreign currencies. These contracts are designated and qualify as
fair value hedging instruments. The fair value was determined using a model with Level 2 inputs
including quoted market prices for contracts with similar terms and maturity dates.
Interest Rate Swaps
We are subject to interest rate risk on our debt and investment of cash and cash equivalents
arising in the normal course of our business, as we do not engage in speculative trading
strategies. We maintain an interest rate management strategy, which primarily uses a mix of fixed
and variable rate debt that is intended to mitigate the exposure to changes in interest rates in
the aggregate for our investment portfolio. In addition, we are currently using interest rate
swaps to manage the economic effect of fixed rate obligations associated with our senior notes so
that the interest payable on the senior notes effectively becomes linked to variable rates.
In June 2009, we entered into two interest rate swap agreements (the Swap Agreements) for a
notional amount of $250 million each in order to hedge changes in the fair market value of our $500
million 6.5% senior notes maturing on November 15, 2013. Under the Swap Agreements, we receive
interest at a fixed rate of 6.5% and pay interest at a floating rate of one-month Libor plus a
spread of 3.67% on one swap and three-month Libor plus a spread of 3.54% on the second swap both
through November 15, 2013. The counterparties are primarily the lenders in our credit facilities.
The Swap Agreements are designated and each qualifies as a fair value hedging instrument. The swap
to three-month Libor is deemed to be 100 percent effective resulting in no gain or loss recorded in
the
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
consolidated statement of operations. The effectiveness of the swap to one-month Libor, which is
highly effective, is calculated as of each period end and any ineffective portion is recognized in
the consolidated statement of operations. The fair value of the Swap Agreements was determined
using a model with Level 2 inputs including quoted market prices for contracts with similar terms
and maturity dates.
Fair Value of Derivative Instruments
The fair value of derivative instruments included in our consolidated balance sheet was as
follows as of December 31, 2009:
Derivative | Balance Sheet Location | Fair Value | ||||||
Foreign Currency Forward Contracts |
Other accrued liabilities | $ | 1 | |||||
Interest Rate Swaps |
Other assets | 7 | ||||||
The effects of derivative instruments in our consolidated statement of operations were as follows for the year ended December 31, 2009 (amounts exclude any income tax effects): | ||||||||
Derivative | Statement of Operations Location | Amount of Gain Recognized in Income | ||||||
Foreign Currency Forward Contracts |
Marketing, general and administrative | $ | 11 | |||||
Interest Rate Swaps |
Interest Expense | 6 |
Concentration of Credit Risk
We sell our products and services to numerous companies in the oil and natural gas industry.
Although this concentration could affect our overall exposure to credit risk, we believe that our
risk is minimized since the majority of our business is conducted with major companies within the
industry. We perform periodic credit evaluations of our customers financial condition and
generally do not require collateral for our accounts receivable. In some cases, we will require
payment in advance or security in the form of a letter of credit or bank guarantee.
We maintain cash deposits with financial institutions that may exceed federally insured
limits. We monitor the credit ratings and our concentration of risk with these financial
institutions on a continuing basis to safeguard our cash deposits.
NOTE 12. INDEBTEDNESS
Total debt consisted of the following at December 31, net of unamortized discount and debt
issuance costs:
2009 | 2008 | |||||||
6.25% Notes due January 2009 with an effective interest rate of 5.77% |
$ | | $ | 325 | ||||
6.00% Notes due February 2009 with an effective interest rate of 6.11% |
| 200 | ||||||
6.50% Senior Notes due November 2013 with an effective interest rate of 6.73% |
504 | 495 | ||||||
7.50% Senior Notes due November 2018 with an effective interest rate of 7.67% |
741 | 740 | ||||||
8.55% Debentures due June 2024 with an effective interest rate of 8.76% |
148 | 148 | ||||||
6.875% Notes due January 2029 with an effective interest rate of 7.08% |
392 | 392 | ||||||
Other debt |
15 | 33 | ||||||
Total debt |
1,800 | 2,333 | ||||||
Less short-term debt and current maturities of long-term debt |
15 | 558 | ||||||
Long-term debt |
$ | 1,785 | $ | 1,775 | ||||
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
During the first quarter of 2009, we repaid $325 million principal amount of our 6.25% notes,
which matured on January 15, 2009, and $200 million principal amount of our 6.00% notes, which
matured on February 15, 2009.
On March 30, 2009, we entered into a credit agreement (the 2009 Credit Agreement) for a
committed $500 million revolving credit facility that expires in March 2010. In addition to the
2009 Credit Agreement, there is a $500 million committed revolving credit facility which expires on
July 7, 2012. Under a committed facility, the lender is obligated to advance funds and/or provide
credit to the borrower as per the terms and conditions stipulated in the credit agreement. At
December 31, 2009, we had $1.0 billion of committed revolving credit facilities with commercial
banks. Both facilities contain certain covenants which, among other things, require the
maintenance of a funded indebtedness to total capitalization ratio (a defined formula per each
agreement), restrict certain merger transactions or the sale of all or substantially all of our
assets or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the
occurrence of certain events of default, our obligations under the facilities may be accelerated.
Such events of default include payment defaults to lenders under the facilities, covenant defaults
and other customary defaults.
At December 31, 2009, we were in compliance with all of the covenants of both committed credit
facilities. There were no direct borrowings under the committed credit facilities during 2009. We
also have an outstanding commercial paper program under which we may issue from time to time up to
$1.0 billion in commercial paper with maturity of no more than 270 days. To the extent we have
commercial paper outstanding, our ability to borrow under the facilities is reduced. At December
31, 2009, we had no outstanding commercial paper.
Maturities of debt at December 31, 2009 are as follows: 2010 $15 million; 2011 $0 million;
2012 $0 million; 2013 $504 million; 2014 $0 million; and $1,281 million thereafter.
NOTE 13. SEGMENT AND RELATED INFORMATION
We are a major supplier of wellbore-related products and technology services and systems and
provide products and services for drilling, formation evaluation, completion and production, and
reservoir technology and consulting to the worldwide oil and natural gas industry. In May 2009, we
reorganized the Company by geography and product lines; however, at this time we continue to review
product line financial information as well as geographic information in deciding how to allocate
resources and in assessing performance. Accordingly, we report results for our product lines under
two segments: the Drilling and Evaluation segment and the Completion and Production segment. We
have aggregated the product lines within each segment because they have similar economic
characteristics and because the long-term financial performance of these product lines is affected
by similar economic conditions. They also operate in the same markets, which includes all of the
major oil and natural gas producing regions of the world. The 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 following product lines: drilling fluids, drill bits, directional drilling, drilling evaluation services, wireline formation evaluation, wireline completion and production services and reservoir technology and consulting. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells as well as consulting services used in the analysis of oil and gas reservoirs. | ||
| The Completion and Production segment consists of the following product lines: wellbore construction and completion, specialty chemicals, artificial lift systems, permanent monitoring systems, chemical injection systems, integrated operations and project management. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells. |
The performance of our segments is evaluated based on segment profit (loss), which is defined
as income before income taxes, interest expense, interest and dividend income, and certain gains
and losses not allocated to the segments.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Summarized financial information is shown in the following table.
Drilling | Completion | |||||||||||||||||||
and | and | Oilfield | Corporate | |||||||||||||||||
Evaluation | Production | Operations | and Other | Total | ||||||||||||||||
2009 |
||||||||||||||||||||
Revenues |
$ | 4,605 | $ | 5,059 | $ | 9,664 | $ | | $ | 9,664 | ||||||||||
Segment profit (loss) |
320 | 728 | 1,048 | (437 | ) | 611 | ||||||||||||||
Total assets |
5,419 | 4,451 | 9,870 | 1,569 | 11,439 | |||||||||||||||
Capital expenditures |
629 | 455 | 1,084 | 2 | 1,086 | |||||||||||||||
Depreciation and amortization |
467 | 233 | 700 | 11 | 711 | |||||||||||||||
2008 |
||||||||||||||||||||
Revenues |
$ | 6,049 | $ | 5,815 | $ | 11,864 | $ | | $ | 11,864 | ||||||||||
Segment profit (loss) |
1,398 | 1,282 | 2,680 | (361 | ) | 2,319 | ||||||||||||||
Total assets |
5,468 | 4,518 | 9,986 | 1,875 | 11,861 | |||||||||||||||
Capital expenditures |
806 | 352 | 1,158 | 145 | 1,303 | |||||||||||||||
Depreciation and amortization |
409 | 185 | 594 | 43 | 637 | |||||||||||||||
2007 |
||||||||||||||||||||
Revenues |
$ | 5,293 | $ | 5,135 | $ | 10,428 | $ | | $ | 10,428 | ||||||||||
Segment profit (loss) |
1,396 | 1,112 | 2,508 | (251 | ) | 2,257 | ||||||||||||||
Total assets |
4,720 | 4,096 | 8,816 | 1,041 | 9,857 | |||||||||||||||
Capital expenditures |
774 | 352 | 1,126 | 1 | 1,127 | |||||||||||||||
Depreciation and amortization |
335 | 162 | 497 | 24 | 521 |
For the years ended December 31, 2009, 2008 and 2007, 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 loss for
the years ended December 31:
2009 | 2008 | 2007 | ||||||||||
Corporate and other expenses |
$ | (298 | ) | $ | (240 | ) | $ | (229 | ) | |||
Interest expense |
(131 | ) | (89 | ) | (66 | ) | ||||||
Interest and dividend income |
6 | 27 | 44 | |||||||||
Gain (loss) on investments |
4 | (25 | ) | | ||||||||
Acquisition-related costs |
(18 | ) | | | ||||||||
Gain on sale of product line |
| 28 | | |||||||||
Litigation settlement |
| (62 | ) | | ||||||||
Total |
$ | (437 | ) | $ | (361 | ) | $ | (251 | ) | |||
The following table presents the details of Corporate and Other total assets at December 31:
2009 | 2008 | 2007 | ||||||||||
Cash and other assets |
$ | 1,266 | $ | 1,684 | $ | 795 | ||||||
Accounts receivable |
17 | 20 | 7 | |||||||||
Current deferred tax asset |
1 | 2 | 1 | |||||||||
Property, plant and equipment |
10 | 28 | 38 | |||||||||
Other tangible assets |
275 | 141 | 200 | |||||||||
Total |
$ | 1,569 | $ | 1,875 | $ | 1,041 | ||||||
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
The following table presents consolidated revenues based on the location of the use of the
products or services for the years ended December 31:
2009 | 2008 | 2007 | ||||||||||
United States |
$ | 3,091 | $ | 4,512 | $ | 3,822 | ||||||
Canada and other |
493 | 666 | 619 | |||||||||
North America |
3,584 | 5,178 | 4,441 | |||||||||
Latin America |
1,134 | 1,127 | 903 | |||||||||
Europe, Africa, Russia, Caspian |
2,925 | 3,386 | 3,076 | |||||||||
Middle East, Asia Pacific |
2,021 | 2,173 | 2,008 | |||||||||
Total |
$ | 9,664 | $ | 11,864 | $ | 10,428 | ||||||
The following table presents net property, plant and equipment based on the location of the
asset at December 31:
2009 | 2008 | 2007 | ||||||||||
United States |
$ | 1,377 | $ | 1,356 | $ | 1,128 | ||||||
Canada and other |
105 | 104 | 91 | |||||||||
North America |
1,482 | 1,460 | 1,219 | |||||||||
Latin America |
354 | 259 | 160 | |||||||||
Europe, Africa, Russia, Caspian |
809 | 679 | 641 | |||||||||
Middle East, Asia Pacific |
516 | 435 | 325 | |||||||||
Total |
$ | 3,161 | $ | 2,833 | $ | 2,345 | ||||||
NOTE 14. EMPLOYEE BENEFIT PLANS
DEFINED BENEFIT PLANS
We have both funded and unfunded noncontributory defined benefit pension plans (Pension
Benefits) covering employees primarily in the U.S., the U.K., Germany and several other countries
in the Middle East region. Under the provisions of the U.S. qualified pension plan, a hypothetical
cash balance account is established for each participant. Such accounts receive pay credits on a
quarterly basis. The quarterly pay credit is based on a percentage according to the employees age
on the last day of the quarter applied to quarterly eligible compensation. In addition to
quarterly pay credits, a cash balance account receives interest credits based on the balance in the
account on the last day of the quarter. The U.S. qualified pension plan also includes frozen
accrued benefits for participants in legacy defined benefit plans. For the majority of the
participants in the U.K. pension plans, we do not accrue benefits as the plans are frozen; however,
there are a limited number of members who still accrue future benefits on a defined benefit basis.
The Germany pension plan is an unfunded plan where benefits are based on creditable years of
service, creditable pay and accrual rates. We also provide certain postretirement health care
benefits (other postretirement benefits), through an unfunded plan, to substantially all U.S.
employees who retire and have met certain age and service requirements.
ASC 715, Compensation Retirement requires an employer to measure the funded status of each
of its plans as of the date of its year end statement of financial position effective for 2008.
The impact of moving our funded status measurement date from October 1 to December
31 was a reduction of $4 million to our 2008 beginning retained earnings.
Funded Status
Below is the reconciliation of the beginning and ending balances of benefit obligations, fair
value of plan assets and the funded status of our plans. For our pension plans, the benefit
obligation is the projected benefit obligation (PBO) and for our other post-retirement benefit
plan, the benefit obligation is the accumulated postretirement benefit obligation (APBO). The
beginning of the year balance was October 1, 2008. The end of year balances are as of December
31 for 2009 and 2008; therefore, for 2008 reconciling items reflected
below represent 15 months of activity as a result of the adoption of ASC 715.
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Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Other Postretirement | ||||||||||||||||||||||||
U.S. Pension Benefits | Non-U.S. Pension Benefits | Benefits | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Change in benefit obligation: |
||||||||||||||||||||||||
Benefit obligation at beginning of year |
$ | 303 | $ | 280 | $ | 227 | $ | 319 | $ | 158 | $ | 156 | ||||||||||||
Service cost |
29 | 38 | 3 | 3 | 8 | 10 | ||||||||||||||||||
Interest cost |
20 | 21 | 15 | 21 | 10 | 11 | ||||||||||||||||||
Actuarial loss (gain) |
51 | (16 | ) | 49 | (36 | ) | (1 | ) | (1 | ) | ||||||||||||||
Benefits paid |
(19 | ) | (16 | ) | (7 | ) | (8 | ) | (13 | ) | (18 | ) | ||||||||||||
Curtailment |
(9 | ) | | (1 | ) | | (5 | ) | | |||||||||||||||
Other |
| (4 | ) | 18 | (2 | ) | | | ||||||||||||||||
Exchange rate adjustments |
| | 23 | (70 | ) | | | |||||||||||||||||
Benefit obligation at end of year |
375 | 303 | 327 | 227 | 157 | 158 | ||||||||||||||||||
Change in plan assets: |
||||||||||||||||||||||||
Fair value of plan assets at beginning of year |
290 | 459 | 197 | 306 | | | ||||||||||||||||||
Actual return on plan assets |
77 | (152 | ) | 24 | (45 | ) | | | ||||||||||||||||
Employer contributions |
2 | 3 | 13 | 17 | 13 | 18 | ||||||||||||||||||
Benefits paid |
(19 | ) | (16 | ) | (7 | ) | (8 | ) | (13 | ) | (18 | ) | ||||||||||||
Other |
(4 | ) | (4 | ) | (1 | ) | | | | |||||||||||||||
Exchange rate adjustments |
| | 22 | (73 | ) | | | |||||||||||||||||
Fair value of plan assets at end of year |
346 | 290 | 248 | 197 | | | ||||||||||||||||||
Funded status underfunded at end of year |
$ | (29 | ) | $ | (13 | ) | $ | (79 | ) | $ | (30 | ) | $ | (157 | ) | $ | (158 | ) | ||||||
The amounts recognized in the consolidated balance sheet consist of the following as of
December 31:
Other Postretirement | ||||||||||||||||||||||||
U.S. Pension Benefits | Non-U.S. Pension Benefits | Benefits | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Noncurrent assets
|
$ | | $ | 4 | $ | | $ | 11 | $ | | $ | | ||||||||||||
Current liabilities
|
(2 | ) | (2 | ) | (4 | ) | (1 | ) | (18 | ) | (15 | ) | ||||||||||||
Noncurrent liabilities
|
(27 | ) | (15 | ) | (75 | ) | (40 | ) | (139 | ) | (143 | ) | ||||||||||||
Net amount recognized
|
$ | (29 | ) | $ | (13 | ) | $ | (79 | ) | $ | (30 | ) | $ | (157 | ) | $ | (158 | ) | ||||||
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 $366 million and $293 million at December 31, 2009 and 2008,
respectively. The ABO for all non-U.S. plans was $313 million and $220 million at December 31,
2009 and 2008, respectively.
Information for the plans with ABOs in excess of plan assets is as follows at December 31:
Other Postretirement | ||||||||||||||||||||||||
U.S. Pension Benefits | Non-U.S. Pension Benefits | Benefits | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Projected benefit obligation |
$ | 375 | $ | 17 | $ | 327 | $ | 43 | n/a | n/a | ||||||||||||||
Accumulated benefit obligation |
366 | 17 | 313 | 36 | $ | 157 | $ | 158 | ||||||||||||||||
Fair value of plan assets |
346 | | 248 | 2 | n/a | n/a |
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
Weighted average assumptions used to determine benefit obligations for these plans are as
follows for the years ended December 31:
Other Postretirement | ||||||||||||||||||||||||
U.S. Pension Benefits | Non-U.S. Pension Benefits | Benefits | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Discount rate |
5.9 | % | 6.4 | % | 5.6 | % | 6.4 | % | 5.9 | % | 6.4 | % | ||||||||||||
Rate of compensation increase |
4.0 | % | 4.0 | % | 4.1 | % | 4.0 | % | n/a | n/a | ||||||||||||||
Social security increase |
3.5 | % | 3.5 | % | 3.1 | % | 3.1 | % | n/a | n/a |
The development of the discount rate for our U.S. plans was based on a bond matching model
whereby a hypothetical bond portfolio of high-quality, fixed-income securities is selected that
will match the cash flows underlying the projected benefit obligation. The discount rate
assumption for our non-U.S. plans reflects the market rate for high-quality, fixed-income
securities.
Accumulated Other Comprehensive Loss
The amounts recognized in accumulated other comprehensive loss consist of the following as of
December 31:
Other Postretirement | ||||||||||||||||||||||||
U.S. Pension Benefits | Non-U.S. Pension Benefits | Benefits | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Net loss |
$ | 150 | $ | 173 | $ | 132 | $ | 83 | $ | | $ | 6 | ||||||||||||
Net prior service cost |
3 | 4 | | | 2 | 4 | ||||||||||||||||||
Total |
$ | 153 | $ | 177 | $ | 132 | $ | 83 | $ | 2 | $ | 10 | ||||||||||||
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 $14 million and $1 million, respectively. The estimated prior service cost for the
other postretirement benefits that will be amortized from accumulated other comprehensive loss into
net periodic benefit cost over the next fiscal year is $1 million.
Net Periodic Benefit Costs
The components of net periodic cost (benefit) are as follows for the years ended December 31:
U.S. Pension Benefits | Non-U.S. Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||
Service cost |
$ | 29 | $ | 30 | $ | 31 | $ | 3 | $ | 2 | $ | 3 | $ | 8 | $ | 8 | $ | 8 | ||||||||||||||||||
Interest cost |
20 | 17 | 16 | 15 | 17 | 18 | 10 | 9 | 9 | |||||||||||||||||||||||||||
Expected return on plan assets |
(25 | ) | (38 | ) | (34 | ) | (15 | ) | (20 | ) | (19 | ) | | | | |||||||||||||||||||||
Amortization of prior service cost |
1 | | | | | | 1 | 1 | 1 | |||||||||||||||||||||||||||
Amortization of net loss |
14 | 1 | 1 | 2 | 1 | 3 | | | | |||||||||||||||||||||||||||
Curtailment |
1 | | | | | | | | | |||||||||||||||||||||||||||
Other |
3 | | | (1 | ) | (2 | ) | | | | | |||||||||||||||||||||||||
Net periodic cost (benefit) |
$ | 43 | $ | 10 | $ | 14 | $ | 4 | $ | (2 | ) | $ | 5 | $ | 19 | $ | 18 | $ | 18 | |||||||||||||||||
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 | ||||||||||||||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||
Discount rate |
6.3 | % | 6.3 | % | 6.0 | % | 6.4 | % | 5.7 | % | 5.0 | % | 6.3 | % | 6.3 | % | 6.0 | % | ||||||||||||||||||
Expected long-term return on
plan assets |
8.5 | % | 8.5 | % | 8.5 | % | 7.2 | % | 7.2 | % | 6.9 | % | n/a | n/a | n/a | |||||||||||||||||||||
Rate of compensation increase |
4.0 | % | 4.0 | % | 4.0 | % | 4.0 | % | 4.1 | % | 3.9 | % | n/a | n/a | n/a | |||||||||||||||||||||
Social security increase |
3.5 | % | 3.5 | % | n/a | 3.1 | % | 3.1 | % | n/a | n/a | n/a | n/a |
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
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.
Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts reported for
other postretirement benefits. As of December 31, 2009, the health care cost trend rate was 7.7%
for employees under age 65 and 6.4% 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 2018.
A one percentage point change in assumed health care cost trend rates would have had the following
effects on 2009:
One Percentage | One Percentage | |||||||
Point Increase | Point Decrease | |||||||
Effect on total of service and interest cost components |
$ | 0.4 | $ | (0.4 | ) | |||
Effect on postretirement welfare benefit obligation |
5.5 | (5.0 | ) |
Plan Assets U.S. Pension Plan
We have investment committees that meet regularly to review the portfolio returns and to
determine asset-mix targets based on asset/liability studies. Third-party investment consultants
assist us in developing asset allocation strategies to determine our expected rates of return and
expected risk for various investment portfolios. The investment committees considered these
strategies in the formal establishment of the current asset-mix targets based on the projected risk
and return levels for all major asset classes.
The investment policy of the U.S. pension plan (the U.S. Plan) was developed after examining
the historical relationships of risk and return among asset classes and the relationship between
the expected behavior of the U.S. Plans assets and liabilities. The investment policy of the U.S.
Plan is designed to provide the greatest probability of meeting or exceeding the U.S. Plans
objectives at the lowest possible risk.
In establishing its risk tolerance, the investment committee for the U.S. Plan (U.S.
Committee) considers its ability to withstand short-term and intermediate-term volatility in
market conditions. The U.S. Committee also reviews the long-term characteristics of various asset
classes, focusing on balancing risk with expected return. Accordingly, the U.S. Committee selected
the following four asset classes as allowable investments for the assets of the U.S. Plan: U.S.
equities, Real Estate, U.S. fixed-income securities, and non-U.S. equities.
The table below presents the fair values of the assets in the U.S. Plan at December 31, 2009,
by asset category and by levels of fair value as further defined in Note 10 of Notes to
Consolidated Financial Statements.
Total Asset | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Value | ||||||||||||
Fixed Income (a) |
$ | | $ | 95 | $ | | $ | 95 | ||||||||
Non-U.S. Equity (b) |
| 78 | | 78 | ||||||||||||
U.S. Small Cap Equity (c) |
| 55 | | 55 | ||||||||||||
S&P 500 Index Fund (d) |
| 48 | | 48 | ||||||||||||
U.S. Large Cap Growth Equity (e) |
| 30 | | 30 | ||||||||||||
U.S. Large Cap Value Equity (f) |
| 23 | | 23 | ||||||||||||
Real Estate Fund (g) |
| | 13 | 13 | ||||||||||||
Real Estate Investment Trust Equity |
| 4 | | 4 | ||||||||||||
Total |
$ | | $ | 333 | $ | 13 | $ | 346 | ||||||||
(a) | A pooled fund with a strategy of investing in fixed income securities. The current allocation includes: 35% in U.S. Government securities; 34% in residential mortgage backed; 26% in corporate bonds; and 5% in index-linked, commercial mortgage-backed and asset-backed securities and cash. | |
(b) | Multi-manager strategy investing in common stocks of non-U.S. listed companies using both value and growth approaches. | |
(c) | Multi-manager strategy investing in common stocks of smaller U.S. listed companies using both value and growth approaches. | |
(d) | A passively managed commingled fund investing in common stocks of the S&P 500 Index. |
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
(e) | Multi-manager growth strategy investing in common stocks of U.S. listed, large capitalization companies. | |
(f) | Multi-manager value strategy investing in common stocks of U.S. listed, large capitalization companies. | |
(g) | Commingled fund investing in a diversified portfolio of U.S. based properties. The current allocation includes: 30% Office, 28% Apartments, 24% Retail, 12% Industrial and 6% Hotel. |
Plan Assets Non-U.S. Pension Plans
The investment policy of the Baker Hughes U.K. pension plan, (the U.K. Plan) covers the
asset allocation that the Trustees believe is the most appropriate for the U.K. Plan in the long
term taking into account the nature of the liabilities they expect to have to meet.
The suitability of the asset allocation and investment policy is reviewed after every
actuarial valuation of the U.K. Plan and will take the form of an asset and liability modeling
study (if required). As part of the review, the Trustees will examine the impact on the volatility
of the U.K. Plans funding level arising from decisions made about the investment arrangements,
including decisions about the investment strategy, about active and passive management and about
manager selection. The Trustees will consider the likely impact on their ability to pay benefits
should the U.K. Plan fail to be fully funded on both an ongoing and discontinuance basis. The
review will also take into account the risk of changes in the Plans funding position resulting
from changes in the U.K. Plans liabilities.
The table below presents the fair values of the assets in our non-U.S. pension plans at
December 31, 2009, by asset category and by levels of fair value as further defined in Note 10 of
Notes to Consolidated Financial Statements.
Total Asset | ||||||||||||||||
Asset Category | Level 1 | Level 2 | Level 3 | Value | ||||||||||||
U.K. Equity Index Fund (a) |
$ | | $ | 68 | $ | | $ | 68 | ||||||||
Global Equity Strategy (b) |
| 54 | | 54 | ||||||||||||
Over 15 Yrs U.K. Gilt Index Fund (c) |
| 44 | | 44 | ||||||||||||
Corporate Bond Index Fund Over 15 Years (d) |
| 39 | | 39 | ||||||||||||
U.K. Property Fund (e) |
| | 19 | 19 | ||||||||||||
Sterling Liquidity Fund (f) |
| 10 | | 10 | ||||||||||||
Over 5 Yrs Index Linked Index Fund (g) |
| 7 | | 7 | ||||||||||||
Insurance contracts |
| | 7 | 7 | ||||||||||||
Total |
$ | | $ | 222 | $ | 26 | $ | 248 | ||||||||
(a) | Invests passively in securities to achieve returns in line with the Financial Times (London) Stock Exchange (FTSE) All-Share Index. | |
(b) | Invests in global securities from the worlds developed markets, including the U.S. and, on an annualized basis, seeks to outperform the Morgan Stanley Capital International World Index by 3%, over a complete market cycle. | |
(c) | Invests passively in securities to achieve returns in line with the FTSE U.K. Gilts Over 15 Year Index. | |
(d) | Invests passively in securities to achieve returns in line with the iBoxx £ non-gilts, over 15 years index. | |
(e) | Invests in a diversified range of property throughout the U.K., principally in the retail, office and industrial/warehouse sectors. | |
(f) | Invests in securities to receive an investment return that is consistent with the security of capital and a high degree of liquidity. | |
(g) | Invests passively in securities to receive returns in line with the FTSE U.K. Gilts Index-Linked Over 5 Years Index. |
The following table presents a rollforward for the fair value of the assets using Level 3
unobservable inputs.
Non-U.S. | ||||||||||||||||
U.S. Property | Non-U.S. | Insurance | ||||||||||||||
Fund | Property Fund | Contracts | Total | |||||||||||||
Beginning balance at January 1, 2009 |
$ | 19 | $ | 18 | $ | 7 | $ | 44 | ||||||||
Unrealized (losses) gains |
(6 | ) | 1 | 1 | (4 | ) | ||||||||||
Net
purchases (sales) |
| | (1 | ) | (1 | ) | ||||||||||
Ending balance at December 31, 2009 |
$ | 13 | $ | 19 | $ | 7 | $ | 39 | ||||||||
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
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. Although we
previously expected to forgo contributions for a period of five to eight years, due to recent
downturns in investment markets and the decline in the value of the pension plan assets, we may be
required to make contributions to the U.S. qualified pension plan within the next one to two years.
In 2010, we expect to contribute between $20 million and $25 million to our U.S. pension plans and
between $15 million and $20 million to the non-U.S. pension plans. In 2010, we also expect to make
benefit payments related to postretirement welfare plans of between $18 million and $20 million.
The following table presents the expected benefit payments over the next ten years. The U.S.
and non-U.S. pension benefit payments are made by the respective pension trust funds. The other
postretirement benefits are net of expected Medicare subsidies of approximately $2 million per year
and are payments that are expected to be made by us.
Other | ||||||||||||
U.S. Pension | Non-U.S. Pension | Postretirement | ||||||||||
Year | Benefits | Benefits | Benefits | |||||||||
2010
|
$ | 20 | $ | 11 | $ | 19 | ||||||
2011
|
23 | 10 | 16 | |||||||||
2012
|
26 | 10 | 16 | |||||||||
2013
|
29 | 12 | 16 | |||||||||
2014
|
32 | 13 | 17 | |||||||||
2015-2019
|
207 | 66 | 95 |
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 are matched by the Company in
cash at the rate of $1.00 per $1.00 employee contribution for the first 5% of the employees salary
and such contributions vest immediately. In addition, we make cash contributions for all eligible
employees between 2% and 5% of their salary depending on the employees age. Such contributions
are fully vested to the employee after three years of employment. The Thrift Plan provides for ten
different investment options, for which the employee has sole discretion in determining how both
the employer and employee contributions are invested. The Thrift Plan does not offer Baker Hughes
company stock as an investment option. Our contributions to the Thrift Plan and several other
non-U.S. defined contribution plans amounted to $129 million, $137 million and $131 million in
2009, 2008 and 2007, 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 $11 million, $9 million and $11 million for 2009, 2008 and 2007,
respectively.
In 2010, we estimate we will contribute between $142 million and $154 million to our defined
contribution plans.
POSTEMPLOYMENT BENEFITS
We provide certain postemployment disability income, medical and other benefits to
substantially all qualifying former or inactive U.S. employees. Income benefits for long-term
disability are provided through a fully-insured plan. The continuation of medical and other
benefits while on disability (Continuation Benefits) are provided through a qualified
self-insured plan. The accrued postemployment liability for Continuation Benefits at December 31,
2009 and 2008 was $13 million and $12 million, respectively, and is included in other liabilities
in our consolidated balance sheet.
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
NOTE 15. COMMITMENTS AND CONTINGENCIES
Leases
At December 31, 2009, 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, 2014 are $126 million, $87
million, $63 million, $40 million and $27 million, respectively, and $102 million in the aggregate
thereafter. Rent expense, which generally includes transportation equipment and warehouse
facilities, was $241 million, $227 million and $179 million for the years ended December 31, 2009,
2008 and 2007, respectively. We have not entered into any significant capital leases during the
three years ended December 31, 2009.
Litigation
We are involved in litigation or proceedings that have arisen in our ordinary business
activities as well as in relation to the pending merger with BJ Services. 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. The accruals
for losses are calculated by estimating losses for claims using historical claim data, specific
loss development factors and other information as necessary.
Department of Justice and Securities and Exchange Commission Matters
On April 26, 2007, the United States District Court, Southern District of Texas, Houston
Division (the Court) unsealed a three-count criminal information (the Information) that had
been filed against us as part of the execution of a Deferred Prosecution Agreement (the DPA)
between us and the Department of Justice (DOJ). The three counts arose out of payments made to
an agent in connection with a project in Kazakhstan and included conspiracy to violate the Foreign
Corrupt Practices Act (FCPA), a substantive violation of the antibribery provisions of the FCPA,
and a violation of the FCPAs books-and-records provisions. All three counts related to our
operations in Kazakhstan during the period from 2000 to 2003. The DPA relates to our March 29,
2002 announcement that the SEC and the DOJ were conducting investigations into allegations of
violations of law relating to Nigeria and other related matters. In connection therewith, the SEC
had issued a formal order of investigation into possible violations of provisions under the FCPA
and issued subpoenas regarding our operations in Nigeria, Angola and Kazakhstan.
On April 26, 2009, the DPA expired and pursuant to a motion filed by the DOJ, the Court issued
an order on April 28, 2009, dismissing the Information on the basis that the Company had fully
complied with its obligations under the DPA.
The DPA also required us to retain an independent monitor (the Monitor) for a term of three
years to assess and make recommendations about our compliance policies and procedures and our
implementation of those procedures. In addition, the Monitor was required to perform two follow up
reviews and to certify whether the anti-bribery compliance program of Baker Hughes, including its
policies and procedures, is appropriately designed and implemented to ensure compliance with the
FCPA, U.S. commercial bribery laws and foreign bribery laws. On April 8, 2009, the Monitor issued
his report for the first of such follow up reviews, and the Monitor issued his certification that
our compliance program is appropriately designed and implemented to ensure such compliance.
Pursuant to the DPA, the DOJ has agreed not to prosecute us for violations of the FCPA based on
information that we have disclosed to the DOJ regarding our operations in Nigeria, Angola,
Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.
On April 26, 2007, the Court also accepted a plea of guilty by our subsidiary Baker Hughes
Services International, Inc. (BHSII) pursuant to a plea agreement between BHSII and the DOJ (the
Plea Agreement) based on similar charges relating to the same conduct. Pursuant to the Plea
Agreement, BHSII agreed to a three-year term of organizational probation. The Plea Agreement
contains provisions requiring BHSII to cooperate with the government, to comply with all federal
criminal law, and to adopt a Compliance Code similar to the one that the DPA requires of the
Company.
Also on April 26, 2007, the SEC filed a Complaint (the SEC Complaint) and a proposed order (2007
Order) against us in the Court. The SEC Complaint and the 2007 Order were filed as part of a
settled civil enforcement action by the SEC, to resolve the civil
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
portion of the governments investigation of us. As part of our agreement with the SEC, we
consented to the filing of the SEC Complaint without admitting or denying the allegations in the
Complaint, and also consented to the entry of the 2007 Order. The SEC Complaint alleged civil
violations of the FCPAs antibribery provisions related to our operations in Kazakhstan, the FCPAs
books-and-records and internal-controls provisions related to our operations in Nigeria, Angola,
Kazakhstan, Indonesia, Russia, and Uzbekistan, and the cease and desist order that we had entered
into with the SEC on September 12, 2001 (2001 Order). In entering into the 2001 Order, we had
neither admitted nor denied the factual allegations contained therein including alleged violations
of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Securities Exchange Act of 1934 that require
issuers to: (x) make and keep books, records and accounts, which, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and
maintain a system of internal accounting controls sufficient to provide reasonable assurances that:
(i) transactions are executed in accordance with managements general or specific authorization;
and (ii) transactions are recorded as necessary: (I) to permit preparation of financial statements
in conformity with generally accepted accounting principles or any other criteria applicable to
such statements, and (II) to maintain accountability for assets. The 2007 Order became effective
on May 1, 2007, which is the date it was confirmed by the Court. The 2007 Order enjoins us from
violating the FCPAs antibribery, books-and-records, and internal-controls provisions. As in the
DPA, it required that we retain the independent monitor to assess our FCPA compliance policies and
procedures.
Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid, in
the second quarter of 2007, $44 million ($11 million in criminal penalties, $10 million in civil
penalties, $20 million in disgorgement of profits and $3 million in pre-judgment interest) to
settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the
potential settlement.
Derivative Lawsuits
On May 4, 2007 and May 15, 2007, the Sheetmetal Workers National Pension Fund and Chris Larson,
respectively, instituted shareholder derivative lawsuits for and on the Companys behalf against
certain current and former members of the Board of Directors and certain current and former
officers, and the Company as a nominal defendant, following the Companys settlement with the DOJ
and SEC in April 2007. On August 17, 2007, the Alaska Plumbing and Pipefitting Industry Pension
Trust also instituted a shareholder derivative lawsuit for and on the Companys behalf against
certain current and former members of the Board of Directors and certain current and former
officers, and the Company as a nominal defendant. On June 6, 2008, the Midwestern Teamsters
Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH instituted a shareholder derivative
lawsuit for and on the Companys behalf against certain current and former members of the Board of
Directors and certain current and former officers, and the Company as a nominal defendant. The
complaints in all four lawsuits allege, among other things, that the individual defendants failed
to implement adequate controls and compliance procedures to prevent the events addressed by the
settlement with the DOJ and SEC. The relief sought in the lawsuits includes a declaration that the
defendants breached their fiduciary duties, an award of damages sustained by the Company as a
result of the alleged breach and monetary and injunctive relief, as well as attorneys and experts
fees. On May 15, 2008, the consolidated complaint of the Sheetmetal Workers National Pension Fund
and the Alaska Plumbing and Pipefitting Industry Pension Trust was dismissed for lack of subject
matter jurisdiction by the Houston Division of the United States District Court for the Southern
District of Texas. The lawsuit brought by Chris Larson in the 215th District Court of Harris
County, Texas was dismissed on September 15, 2008. The lawsuit brought by the Midwestern Teamsters
Pension Trust Fund and Oppenheim Kapitalanlagegesellschaft mbH in the Houston Division of the
United States District Court for the Southern District of Texas was dismissed on May 26, 2009. The
time period for plaintiffs to file a Notice of Appeal in each of the cases has expired.
BJ Services Merger Related Stockholder Lawsuits
Delaware Cases
On September 1, 2009, three purported stockholder class action lawsuits styled Laborers Local
235 Benefit Fund v. Stewart, et al., The Booth Family Trust v. Huff, et al., and Dugdale v. Huff,
et al., were filed in the Court of Chancery of the State of Delaware (the Delaware Chancery
Court) on behalf of the public stockholders of BJ Services, with respect to the Merger Agreement,
dated as of August 30, 2009, among Baker Hughes, its wholly owned subsidiary, BSA Acquisition LLC,
a Delaware limited liability company (Merger Sub) and BJ Services, whereby, subject to
satisfaction of the conditions to closing, BJ Services will merge with and into Merger Sub (the
Merger), with Merger Sub continuing as the surviving entity after the Merger. Each action names
BJ Services, the current members of the BJ Services Board of Directors (the BJ Services Board)
and the Company as defendants (collectively the Defendants).
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
In these Delaware actions, and the follow-on actions discussed below, the plaintiffs allege,
among other things, that the members of the BJ Services Board breached their fiduciary duties by
failing to properly value BJ Services, failing to take steps to maximize the value of BJ Services
to its public stockholders, and avoiding a competitive bidding process. The actions each allege
that the Company aided and abetted the purported breaches by the BJ Services Board. The plaintiffs
in each lawsuit seek, among other things, injunctive relief with respect to the Merger.
To date, six additional purported class action lawsuits have been filed in the Delaware
Chancery Court on behalf of the public stockholders of BJ Services against the Company, BJ Services
and the BJ Services Board, including: Myers, v. BJ Services, et al., which was filed on September
4, 2009, Garden City Employees Retirement System v. BJ Services, et al., which was filed on
September 8, 2009, Saratoga Advantage Trust-Energy & Basic Materials Portfolio v. Huff, et al.,
which was filed on September 8, 2009, Stationary Engineers Local 39 Pension Trust Fund v. Stewart,
et al., which was filed on September 11, 2009, Jacobs v. Stewart, et al., which was filed on
September 23, 2009, and Lyle v. BJ Services Company, et al., which was filed on October 1, 2009.
On September 25, 2009, the Delaware Chancery Court entered an order consolidating the lawsuits
filed in the Delaware Chancery Court. On October 6, 2009, the Delaware Chancery Court entered an
order implementing a bench ruling of October 5, 2009, resolving competing motions for appointment
of lead counsel in the Delaware Chancery Court and designating the law firm of Faruqi & Faruqi, LLP
of New York, New York as lead counsel and Rosenthal, Monhait & Goddess, P.A. of Wilmington,
Delaware as liaison counsel. On October 14, 2009, the Delaware Chancery Court entered a
supplemental consolidation order adding the October 1, 2009 Lyle complaint to the consolidated
action.
On October 16, 2009, lead counsel for plaintiffs in the consolidated class action, In re: BJ
Services Company Shareholders Litigation, C.A. No. 4851-VCN, served a Verified Consolidated Amended
Class Action Complaint (the Amended Complaint) in the Delaware Court of Chancery. The Amended
Complaint, among other things, adds an officer of BJ Services (Jeffrey E. Smith, the Executive Vice
President-Finance and CFO of BJ Services) as a defendant, contains new factual allegations about
the negotiations between BJ Services and the Company, and alleges the Form S-4 Registration
Statement and preliminary joint proxy statement/prospectus, filed with the Securities and Exchange
Commission on October 14, 2009, omits and misrepresents material information.
Texas Cases
On September 4, 2009, a purported stockholder class action lawsuit styled Garden City
Employees Retirement System v. BJ Services Company, et al., was filed in the 80th Judicial
District Court of Harris County, Texas, on behalf of the public stockholders of BJ Services with
respect to the Merger Agreement naming BJ Services, the current members of the BJ Services Board,
the Company and Merger Sub as defendants.
To date, three additional actions have been filed against the Company, BJ Services and its
Board in District Courts in Harris County, Texas. They are: (1) Johnson v. Stewart, et al., filed
on September 11, 2009, (2) Saratoga Advantage Trust Energy & Basic Materials Portfolio v. Huff,
et al., filed on September 11, 2009, and (3) Matt v. Huff, et al., which was filed on September 21,
2009. The lead plaintiff and plaintiffs counsel in the Garden City and Saratoga Advantage Trust
cases filed in Texas also filed the cases of the same name in Delaware that are listed above. The
Texas actions make substantially the same allegations as were initially asserted in the Delaware
actions, and seek the same relief.
On October 9, 2009, the Harris County Court consolidated the Texas actions and restyled the
action as Garden City Employees Retirement System, et al. v. BJ services Company, et al., Cause
No. 2009-57320, 80th Judicial District of Harris County, Texas. No amended consolidated
complaint has been filed as of the date of this Annual Report on Form 10-K.
On October 20, 2009, the Court of Appeals for the First District of Texas at Houston granted
Defendants emergency motion to stay the Texas cases pending its decision on defendants mandamus
petition seeking a stay of the Texas litigation pending adjudication of the first-filed cases in
Delaware.
Proposed Settlement of Delaware and Texas Cases
The Company believes that the Delaware and Texas actions are without merit, and that it has valid
defenses to all claims. Nevertheless, in an effort to minimize further cost, expense, burden and
distraction of any litigation relating to such lawsuits, on February 9, 2010, the parties to the
Delaware and Texas actions entered into a Memorandum of Understanding regarding the terms of
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
settlement of such lawsuits. The Memorandum of Understanding resolves the allegations by the
plaintiffs against the defendants in connection with the merger and provides a release and
settlement by the purported class of the BJ Services stockholders of all claims against BJ
Services, its directors and an officer and Baker Hughes, and their affiliates and agents, in
connection with the merger. In
exchange for such release and settlement, the parties agreed, after discussions on an arms length
basis, that Baker Hughes and BJ Services provide additional supplemental disclosures in the joint
proxy statement/prospectus included in a registration statement on
Form S-4 filed by Baker Hughes on February 9, 2010 with the SEC. The
proposed settlement includes an agreement that neither BJ Services nor Baker Hughes will oppose
plaintiffs counsels application for BJ Services to pay attorneys fees and costs in an amount to
be determined by the court up to $700,000. In general, the terms of the Memorandum of
Understanding will not become legally binding unless and until further definitive documentation is
entered into and court approval is obtained. The settlement is contingent upon consummation of the
merger. There can be no assurance as to when or whether any of the foregoing conditions will be
satisfied. In the event that these conditions are not satisfied, the Company intends to continue to
vigorously defend these actions.
Environmental Matters
Our past and present operations include activities which are subject to extensive domestic
(including U.S. federal, state and local) and international environmental regulations with regard
to air, land and water quality and other environmental matters. Our environmental procedures,
policies and practices are designed to ensure compliance with existing laws and regulations and to
minimize the possibility of significant environmental damage.
We are involved in voluntary remediation projects at some of our present and former
manufacturing locations or other facilities, the majority of which relate to properties obtained in
acquisitions or to sites no longer actively used in operations. On rare occasions, remediation
activities are conducted as specified by a government agency-issued consent decree or agreed order.
Remediation costs are accrued based on estimates of probable exposure using currently available
facts, existing environmental permits, technology and presently enacted laws and regulations.
Remediation cost estimates include direct costs related to the environmental investigation,
external consulting activities, governmental oversight fees, treatment equipment and costs
associated with long-term operation, maintenance and monitoring of a remediation project.
We have also been identified as a potentially responsible party (PRP) in remedial activities
related to various Superfund sites. We participate in the process set out in the Joint
Participation and Defense Agreement to negotiate with government agencies, identify other PRPs,
determine each PRPs allocation and estimate remediation costs. We have accrued what we believe to
be our pro-rata share of the total estimated cost of remediation and associated management of these
Superfund sites. This share is based upon the ratio that the estimated volume of waste we
contributed to the site bears to the total estimated volume of waste disposed at the site.
Applicable United States federal law imposes joint and several liability on each PRP for the
cleanup of these sites leaving us with the uncertainty that we may be responsible for the
remediation cost attributable to other PRPs who are unable to pay their share. No accrual has been
made under the joint and several liability concept for those Superfund sites where our
participation is de minimis since we believe that the probability that we will have to pay material
costs above our volumetric share is remote. We believe there are other PRPs who have greater
involvement on a volumetric calculation basis, who have substantial assets and who may be
reasonably expected to pay their share of the cost of remediation. For those Superfund sites where
we are a significant PRP, remediation costs are estimated to include recalcitrant parties. In some
cases, we have insurance coverage or contractual indemnities from third parties to cover a portion
of or the ultimate liability.
Our total accrual for environmental remediation is $18 million and $17 million, which includes
accruals of $6 million and $6 million for the various Superfund sites, at December 31, 2009 and
2008, 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 connection with the settlement of litigation with ReedHycalog, in June 2008, the Company
paid ReedHycalog $70 million in royalties for prior use of certain patented technologies, and
ReedHycalog paid the Company $8 million in royalties for the license of certain Company patented
technologies. The net pre-tax charge of $62 million for the settlement of this litigation is
reflected in the 2008 consolidated statement of operations.
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 $692 million at December 31, 2009. We also had commitments outstanding for
purchase obligations related to capital expenditures and inventory under purchase orders and
contracts
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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)
Notes to Consolidated Financial Statements (continued)
of approximately $221 million at December 31, 2009. 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. ACCUMULATED OTHER COMPREHENSIVE LOSS
The following is a reconciliation of Accumulated Other Comprehensive Loss:
Pensions and | Foreign | Accumulated | ||||||||||
Other | Currency | Other | ||||||||||
Postretirement | Translation | Comprehensive | ||||||||||
Benefits | Adjustments | Loss | ||||||||||
Balance at December 31, 2007 |
$ | (56 | ) | $ | 12 | $ | (44 | ) | ||||
Translation adjustments |
| (354 | ) | (354 | ) | |||||||
Amortization of prior service cost |
1 | | 1 | |||||||||
Amortization of actuarial net loss |
2 | | 2 | |||||||||
Actuarial net losses arising in the year |
(222 | ) | | (222 | ) | |||||||
Adjustment to reflect change in measurement date |
1 | | 1 | |||||||||
Effect of exchange rate |
26 | | 26 | |||||||||
Deferred taxes |
67 | | 67 | |||||||||
Balance at December 31, 2008 |
(181 | ) | (342 | ) | (523 | ) | ||||||
Translation adjustments |
| 122 | 122 | |||||||||
Amortization of prior service cost |
1 | | 1 | |||||||||
Amortization of actuarial net loss |
16 | | 16 | |||||||||
Actuarial net losses arising in the year |
(22 | ) | | (22 | ) | |||||||
Effect of exchange rate |
(10 | ) | | (10 | ) | |||||||
Deferred taxes |
2 | | 2 | |||||||||
Balance at December 31, 2009 |
$ | (194 | ) | $ | (220 | ) | $ | (414 | ) | |||
NOTE 17. QUARTERLY DATA (UNAUDITED)
First | Second | Third | Fourth | Total | ||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Year | ||||||||||||||||
2009 |
||||||||||||||||||||
Revenues |
$ | 2,668 | $ | 2,336 | $ | 2,232 | $ | 2,428 | $ | 9,664 | ||||||||||
Gross profit (1) |
599 | 437 | 383 | 451 | 1,870 | |||||||||||||||
Net income |
195 | 87 | 55 | 84 | 421 | |||||||||||||||
Basic earnings per share |
0.63 | 0.28 | 0.18 | 0.27 | 1.36 | |||||||||||||||
Diluted earnings per share |
0.63 | 0.28 | 0.18 | 0.27 | 1.36 | |||||||||||||||
Dividends per share |
0.15 | 0.15 | 0.15 | 0.15 | 0.60 | |||||||||||||||
Common stock market prices: |
||||||||||||||||||||
High |
38.08 | 42.33 | 44.01 | 47.67 | ||||||||||||||||
Low |
26.58 | 29.22 | 33.41 | 38.04 | ||||||||||||||||
2008 |
||||||||||||||||||||
Revenues |
$ | 2,670 | $ | 2,998 | $ | 3,010 | $ | 3,186 | $ | 11,864 | ||||||||||
Gross profit (1) |
798 | 895 | 879 | 912 | 3,484 | |||||||||||||||
Net income |
395 | 379 | 429 | 432 | 1,635 | |||||||||||||||
Basic earnings per share |
1.28 | 1.24 | 1.40 | 1.41 | 5.32 | |||||||||||||||
Diluted earnings per share |
1.27 | 1.23 | 1.39 | 1.41 | 5.30 | |||||||||||||||
Dividends per share |
0.13 | 0.13 | 0.15 | 0.15 | 0.56 | |||||||||||||||
Common stock market prices: |
||||||||||||||||||||
High |
81.34 | 89.56 | 88.57 | 60.54 | ||||||||||||||||
Low |
63.90 | 68.50 | 60.93 | 26.02 |
(1) | Represents revenues less cost of sales, cost of services and rentals and research and engineering. |
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this annual report, we have evaluated the effectiveness
of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of
the Exchange Act of 1934, as amended (the Exchange Act). This evaluation was carried out under
the supervision and with the participation of our management, including our principal executive
officer and principal financial officer. Based on this evaluation, these officers have concluded
that, as of December 31, 2009, our disclosure controls and procedures, as defined by Rule 13a-15(e)
of the Exchange Act, are effective at a reasonable assurance level.
Disclosure controls and procedures are our controls and other procedures that are designed to
ensure that information required to be disclosed by us in the reports that we file or submit under
the Exchange Act, such as this annual report, is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that information required
to be disclosed by us in the reports that we file under the Exchange Act is accumulated and
communicated to our management, including our principal executive officer and principal financial
officer, as appropriate, to allow timely decisions regarding required disclosure.
Design and Evaluation of Internal Control Over Financial Reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of
their assessment of the design and effectiveness of our internal controls over financial reporting
as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2009. Deloitte &
Touche LLP, the Companys independent registered public accounting firm, has issued an attestation
report on the effectiveness of the Companys internal control over financial reporting.
Managements report and the independent registered public accounting firms attestation report are
included in Item 8 under the caption entitled Managements Report on Internal Control Over
Financial Reporting and Report of Independent Registered Public Accounting Firm and are
incorporated herein by reference.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter
ended December 31, 2009 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, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates
for our principal executive officer, principal financial officer and principal accounting officer
are described in Item 1. Business of this Annual Report. Information concerning our directors is
set forth in the sections entitled Proposal No. 1, Election of Directors, and Corporate
Governance Committees of the Board Audit/Ethics
Committee in our Definitive Proxy Statement for the 2010
Annual Meeting of Stockholders to be filed with the SEC pursuant to
the Exchange Act within 120 days of the end of our fiscal year on
December 31, 2009 (Proxy Statement), which sections are
incorporated herein by reference. For information regarding our executive officers, see Item 1.
Business Executive Officers in this Annual Report on Form 10-K. Additional information
regarding 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.
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ITEM 11. EXECUTIVE COMPENSATION
Information for this item is set forth in the following sections of our Proxy Statement, which
sections are incorporated herein by reference: Compensation Discussion and Analysis, Executive
Compensation, Director Compensation, Compensation Committee Interlocks and Insider
Participation and Compensation Committee Report.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Information concerning security ownership of certain beneficial owners and our management is
set forth in the sections entitled Voting Securities and Security Ownership of Management in
our Proxy Statement, which sections are incorporated herein by reference.
Our Board of Directors has approved procedures for use under our Securities Trading and
Disclosure Policy to permit our employees, officers and directors to enter into written trading
plans complying with Rule 10b5-1 under the Exchange Act. Rule
10b5-1 provides criteria under which such an individual may establish a prearranged plan to buy or
sell a specified number of shares of a companys stock over a set period of time. Any such plan
must be entered into in good faith at a time when the individual is not in possession of material,
nonpublic information. If an individual establishes a plan satisfying the requirements of Rule
10b5-1, such individuals subsequent receipt of material, nonpublic information will not prevent
transactions under the plan from being executed. Certain of our officers have advised us that they
have and may enter into a stock sales plan for the sale of shares of our common stock which are
intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the
Company has and may in the future enter into repurchases of our common stock under a plan that
complies with Rule 10b5-1 or Rule 10b-18 of the Exchange Act.
Equity Compensation Plan Information
The information in the following table is presented as of December 31, 2009 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, except per share prices).
Number of Securities | ||||||||||||
Number of | Remaining Available | |||||||||||
Securities to be | for Future Issuance | |||||||||||
Issued Upon | Weighted Average | Under Equity | ||||||||||
Exercise of | Exercise Price of | Compensation Plans | ||||||||||
Outstanding | Outstanding | (excluding securities | ||||||||||
Equity Compensation Plan | Options, Warrants | Options, Warrants | reflected in the first | |||||||||
Category | and Rights | and Rights | column) | |||||||||
Stockholder-approved plans (excluding
Employee Stock Purchase Plan) |
2.0 | $ | 53.64 | 1.4 | ||||||||
Nonstockholder-approved plans (1) |
3.7 | 48.27 | 0.6 | |||||||||
Subtotal (except for weighted average
exercise price) |
5.7 | 50.17 | 2.0 | |||||||||
Employee Stock Purchase Plan (2) |
| | 7.2 | |||||||||
Total |
5.7 | $ | 50.17 | 9.2 | ||||||||
(1) | The table includes the following nonstockholder-approved plans: the 1998 Employee Stock Option Plan, the 2002 Employee Long-Term Incentive Plan and the Director Compensation Deferral Plan. A description of each of these plans is set forth below. | |
(2) | The per share purchase price under the Baker Hughes Incorporated Employee Stock Purchase Plan is determined in accordance 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. |
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Our nonstockholder-approved plans are described below:
1998 Employee Stock Option Plan
The Baker Hughes Incorporated 1998 Employee Stock Option Plan (the 1998 ESOP) was adopted
effective as of October 1, 1998. The number of shares authorized for issuance under the 1998 ESOP
was 7.0 million shares. Nonqualified stock options may be granted under the 1998 ESOP to our
employees. The exercise price of the options will be equal to the fair market value per share of
our common stock on the date of grant, and option terms may be up to ten years. Under the terms
and conditions of the option award agreements for options issued under the 1998 ESOP, options
generally vest and become exercisable in installments over the optionees period of service, and
the options vest on an accelerated basis in the event of a change in control. As of December 31,
2009, options covering approximately 0.1 million shares of our common stock were outstanding under
the 1998 ESOP, options covering approximately 9,000 shares were exercised during fiscal year 2009.
There are no shares available for grants of future options as the plan expired on October 1, 2008.
2002 Employee Long-Term Incentive Plan
The Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (the 2002 Employee
LTIP) was adopted effective as of March 6, 2002. The 2002 Employee LTIP permits the grant of
awards as nonqualified stock options, stock appreciation rights, restricted stock, restricted stock
units, performance shares, performance units, stock awards and cash-based awards to our corporate
officers and key employees. The number of shares authorized for issuance under the 2002 Employee
LTIP is 9.5 million, with no more than 69,000 shares
available for future grants (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, 2009, options covering approximately 3.5 million
shares of our common stock were outstanding under the 2002 Employee
LTIP and options covering
approximately 24,000 shares were exercised during fiscal year 2009.
Performance Shares and Units; Cash-Based Awards. Performance shares may be granted to
employees in the amounts and upon the terms determined by the Compensation Committee of our Board
of Directors, but must be limited to no more than 1.0 million shares to any one employee in any one
fiscal year. Performance units and cash-based awards may be granted to employees in amounts and
upon the terms determined by the Compensation Committee, but must be limited to no more than $10
million for any one employee in any one fiscal year. The performance measures that may be used to
determine the extent of the actual performance payout or vesting include, but are not limited to,
net earnings; earnings per share; return measures; cash flow return on investments (net cash flows
divided by owners equity); earnings before or after taxes, interest, depreciation and/or
amortization; share price (including growth measures and total shareholder return) and Baker Value
Added (our metric that measures operating profit after tax less the cost of capital employed).
Restricted Stock and Restricted Stock Units. With respect to awards of restricted stock and
restricted stock units, the Compensation Committee will determine the conditions or restrictions on
the awards, including whether the holders of the restricted stock or restricted stock units will
exercise full voting rights (in the case of restricted stock awards only) or receive dividends and
other distributions during the restriction period. At the time the award is made, the Compensation
Committee will determine the right to receive unvested restricted stock or restricted units after
termination of service. Awards of restricted stock are limited to 1.0 million shares in any one
year to any one individual. Awards of restricted stock units are limited to 1.0 million units in
any one year to any one individual.
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
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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, 2009, options
covering 3,313 shares of our common stock were outstanding under the Deferral Plan, there were no
shares exercised during fiscal 2009 and approximately 0.5 million shares remained available for
future options.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information for this item is set forth in the sections entitled Corporate
Governance-Director Independence and Certain Relationships and Related Transactions in our Proxy
Statement, which sections are incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accounting fees and services is set forth in the section
entitled Fees Paid to Deloitte & Touche LLP in our Proxy Statement, which section is incorporated
herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) | List of Documents filed as part of this Report. |
(1) | Financial Statements | ||
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 |
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(3) | Exhibits | |
Each exhibit identified below is filed as a part of this report. Exhibits designated with an * are filed as an exhibit to this Annual Report on Form 10-K. Exhibits designated with a + are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference. |
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, 2007). | ||
3.2 | Restated Bylaws of Baker Hughes Incorporated effective as of February 19, 2010 except for Article III, Section 1 which will not be effective unless and until the closing of the pending merger with BJ Services Company (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed February 23, 2010). | ||
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 there under equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request. | ||
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, 2007). | ||
4.3 | Restated Bylaws of Baker Hughes Incorporated effective as of February 19, 2010 except for Article III, Section 1 which will not be effective unless and until the closing of the pending merger with BJ Services Company (filed as Exhibit 3.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed February 23, 2010). | ||
4.4 | 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). | ||
4.5 | Indenture dated October 28, 2008, between Baker Hughes Incorporated and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). | ||
4.6 | Officers Certificate of Baker Hughes Incorporated dated October 28 2008 establishing the 6.50% Senior Notes due 2013 and the 7.50% Senior Notes due 2018 (filed as Exhibit 4.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). | ||
4.7 | Form of 6.50% Senior Notes Due 2013 (filed as Exhibit 4.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). | ||
4.8 | Form of 7.50% Senior Notes Due 2018 (filed as Exhibit 4.4 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 29, 2008). | ||
10.1+ | Amendment and Restatement of Employment Agreement between Chad C. Deaton and Baker Hughes Incorporated dated as of January 1, 2009 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008). | ||
10.2+ | Form of Amended and Restated Change in Control Agreement between Baker Hughes Incorporated and each of the executive officers effective as of January 1, 2009. | ||
10.3+ | 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). | ||
10.4+ | Agreement regarding restricted stock award issued to Chad C. Deaton on October 25, 2004 in the amount of 80,000 shares of Company Common Stock (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004). |
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10.5+ | Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated dated as of March 27, 2006 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2006). | ||
10.6+ | Amendment and Restatement of the Baker Hughes Incorporated Change in Control Severance Plan effective as of January 1, 2009 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008). | ||
10.7+ | 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). | ||
10.8+ | Form of Amendment to the Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers effective as of January 1, 2009 (filed as Exhibit 10.4 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008). | ||
10.9+ | 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). | ||
10.10+ | Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of January 1, 2009 (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008). | ||
10.11+ | Amendment to Baker Hughes Incorporated Director Compensation Deferral Plan effective as of January 1, 2009 (filed as Exhibit 10.5 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). | ||
10.12+ | Baker Hughes Incorporated Executive Severance Plan, as amended and restated on February 7, 2008 (filed as Exhibit 10.17 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007). | ||
10.13+ | Amendment to Exhibit A of Baker Hughes Incorporated Executive Severance Plan as of July 20, 2009 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2009). | ||
10.14+ | Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended and restated on February 20, 2008 (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007). | ||
10.15+ | Amendment to the Baker Hughes Annual Incentive Compensation Plan effective as of January 1, 2009 (filed as Exhibit 10.7 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). | ||
10.16+ | Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2009 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008). | ||
10.17+ | Amendment to the Baker Hughes Incorporated Supplemental Retirement Plan effective as of January 1, 2009 (filed as Exhibit 10.6 to Current Report of Baker Hughes Incorporated on Form 8-K filed on December 19, 2008). | ||
10.18+ | 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). | ||
10.19+ | 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). | ||
10.20+ | Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333-87372 of Baker Hughes Incorporated on Form S-8 filed May 1, 2002). |
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10.21+ | Amendment to Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan, effective July 24, 2008 (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008). | ||
10.22+ | 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). | ||
10.23+ | Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 of Baker Hughes Incorporated to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005). | ||
10.24+ | Amendment to Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan effective July 24, 2008 (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2008). | ||
10.25* | Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of January 1, 2010. | ||
10.26+ | 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). | ||
10.27+ | 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). | ||
10.28+ | 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). | ||
10.29+ | 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). | ||
10.30+* | Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement with Terms and Conditions for officers. | ||
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 Incentive Stock Option Agreement with Terms and Conditions for officers. | ||
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 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004). | ||
10.37+* | Form of Baker Hughes Incorporated Restricted Stock Award with Terms and Conditions for officers. |
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10.38+ | Form of Baker Hughes Incorporated Restricted Stock Unit Agreement, including Terms and Conditions (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007). | ||
10.39+ | Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004). | ||
10.40 | Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004). | ||
10.41+* | Form of Baker Hughes Incorporated Restricted Stock Unit Award Agreement and Terms and Conditions for officers. | ||
10.42+ | Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors (filed as Exhibit 10.40 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005). | ||
10.43+ | Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors (filed as Exhibit 10.41 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005). | ||
10.44+ | Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2007). | ||
10.45+ | Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005). | ||
10.46+ | Form of Amended Baker Hughes Incorporated 2006 Performance Unit Award Terms and Conditions (filed as Exhibit 10.8 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008). | ||
10.47+ | Form of Amended Baker Hughes Incorporated 2007 Performance Unit Award Terms and Conditions (filed as Exhibit 10.9 to Current Report of Baker Hughes Incorporated on Form 8-K filed December 19, 2008). | ||
10.48+* | Form of Baker Hughes Incorporated Performance Unit Award Agreement and terms and Conditions for officers. | ||
10.49+ | Performance Goals for the Performance Unit Award granted in 2006 (filed as Exhibit 10.43 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005). | ||
10.50+ | Form of Performance Goals for the Performance Unit Awards (filed as Exhibit 10.44 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2006). | ||
10.51+ | Form of 2009 Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2009). | ||
10.52+* | Compensation Table for Named Executive Officers and Directors. | ||
10.53 | 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). | ||
10.54 | First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on June 12, 2006). |
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10.55 | Second Amendment to the Credit Agreement dated May 31, 2007, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed June 4, 2007). | ||
10.56 | Third Amendment to Credit Agreement dated as of April 1, 2008, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent, and fifteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed April 2, 2008). | ||
10.57 | Credit Agreement dated as of March 30, 2009, among Baker Hughes Incorporated, JP Morgan Chase Bank, N.A., as Administrative Agent, and thirteen 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 March 31, 2009). | ||
10.58 | Agreement of Resignation, Appointment and Acceptance by and among Baker Hughes Incorporated, Citibank, N.A. and the Bank of New York Trust Company, N.A. dated as of April 26, 2007, effective May 1, 2007 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
10.59 | 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). | ||
10.60+ | 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). | ||
10.61 | Deferred Prosecution Agreement between Baker Hughes Incorporated and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
10.62 | Plea Agreement between Baker Hughes Services International, Inc. and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
10.63+ | Letter Agreement between Baker Hughes Incorporated and David H. Barr dated February 25, 2009 (filed as Exhibit 10.59 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2008). | ||
10.64+ | Consulting Agreement between Baker Hughes Oilfield Operations, Inc. and David H. Barr dated February 25, 2009 (filed as Exhibit 10.60 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2008). | ||
10.65 | Agreement and Plan of Merger dated as of August 30, 2009, among Baker Hughes Incorporated, BSA Acquisition LLC and BJ Services Company (filed as Exhibit 2.1 to Current Report of Baker Hughes incorporated on Form 8-K filed August 31, 2009). | ||
21.1* | Subsidiaries of Registrant. | ||
23.1* | Consent of Deloitte & Touche LLP. | ||
31.1* | Certification of Chad C. Deaton, Chief Executive Officer, dated February 25, 2009, 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 25, 2009, 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 25, 2009, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended. |
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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). | ||
99.2 | Baker Hughes Incorporated Information document filed on April 26, 2007, by the United States Attorneys Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
99.3 | Baker Hughes Services International, Inc. Information document filed on April 26, 2007, by the Untied States Attorneys Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
99.4 | Sentencing Memorandum and Motion for Waiver of Pre-Sentence Investigation of Baker Hughes Services International, Inc. (filed as Exhibit 99.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
99.5 | Baker Hughes Services International, Inc. Sentencing Letter from the United States Department of Justice dated April 24, 2007 (filed as Exhibit 99.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
99.6 | The Complaint by the Securities and Exchange Commission vs. Baker Hughes Incorporated filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007). | ||
99.7 | Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007). |
**101.INS
|
XBRL Instance Document | |
**101.SCH
|
XBRL Schema Document | |
**101.CAL
|
XBRL Calculation Linkbase Document | |
**101.LAB
|
XBRL Label Linkbase Document | |
**101.PRE
|
XBRL Presentation Linkbase Document | |
**101.DEF
|
XBRL Definition Linkbase Document |
** | Furnished with this Form 10-K, not filed. |
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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 25, 2010 | /s/ CHAD C. DEATON | |||
Chad C. Deaton | ||||
Chairman of the Board, President and Chief Executive Officer |
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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.
Signature | Title | Date | ||
/s/ CHAD C. DEATON
|
Chairman of the Board, President and Chief Executive Officer | February 25, 2010 | ||
(principal executive officer) | ||||
/s/ PETER A. RAGAUSS
|
Senior Vice President and Chief Financial Officer | February 25, 2010 | ||
(principal financial officer) | ||||
/s/ ALAN J. KEIFER
|
Vice President and Controller | February 25, 2010 | ||
(principal accounting officer) | ||||
/s/ LARRY D. BRADY
|
Director | February 25, 2010 | ||
/s/ CLARENCE P. CAZALOT, JR.
|
Director | February 25, 2010 | ||
/s/ EDWARD P. DJEREJIAN
|
Director | February 25, 2010 | ||
/s/ ANTHONY G. FERNANDES
|
Director | February 25, 2010 | ||
/s/ CLAIRE W. GARGALLI
|
Director | February 25, 2010 | ||
/s/ PIERRE H. JUNGELS
|
Director | February 25, 2010 | ||
/s/ JAMES A. LASH
|
Director | February 25, 2010 | ||
/s/ J. LARRY NICHOLS
|
Director | February 25, 2010 | ||
/s/ H. JOHN RILEY, JR.
|
Director | February 25, 2010 | ||
/s/ CHARLES L. WATSON |
Director | February 25, 2010 | ||
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Baker Hughes Incorporated
Schedule II Valuation and Qualifying Accounts
Balance at | Charged to | Charged to | Balance at | |||||||||||||||||
Beginning | Cost and | Other | End of | |||||||||||||||||
(In millions) | of Period | Expenses | Write-offs (1) | Accounts(2) | Period | |||||||||||||||
Year ended December 31, 2009 |
||||||||||||||||||||
Reserve for doubtful accounts receivable |
$ | 74 | $ | 94 | $ | (12 | ) | $ | 1 | $ | 157 | |||||||||
Reserve for inventories |
244 | 101 | (53 | ) | 5 | 297 | ||||||||||||||
Year ended December 31, 2008 |
||||||||||||||||||||
Reserve for doubtful accounts receivable |
59 | 31 | (15 | ) | (1 | ) | 74 | |||||||||||||
Reserve for inventories |
221 | 61 | (30 | ) | (8 | ) | 244 | |||||||||||||
Year ended December 31, 2007 |
||||||||||||||||||||
Reserve for doubtful accounts receivable |
51 | 22 | (10 | ) | (4 | ) | 59 | |||||||||||||
Reserve for inventories |
212 | 43 | (37 | ) | 3 | 221 |
(1) | Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless. | |
(2) | Represents reclassifications, currency translation adjustments and divestitures. |
89