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Baker Hughes 10-K 2010
e10vk
Table of Contents

 
 
UNITED STATES
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)
Registrant’s 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 registrant’s 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 registrant’s 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 Registrant’s 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
         
    Page
Part I
 
       
    2  
    12  
    18  
    18  
    18  
    18  
Part II
 
       
    18  
    21  
    22  
    39  
    41  
    77  
    77  
    77  
 
       
Part III
 
       
    77  
    78  
    78  
    80  
    80  
 
       
Part IV
 
       
    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

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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
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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     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 customer’s 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.

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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 reservoir’s 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 well’s 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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while the well is being drilled. Wireline logging measurements can be made before the well’s 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 well’s 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 customer’s 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 hanger’s expandable slips grip the inside of the casing and support the weight of the liner below. Multilateral completion systems enable two or more zones to be produced from a single well, using multiple horizontal branches. Expandable metal technology involves the permanent downhole expansion of a variety of tubular products used in drilling, completion and well remediation applications.
     Cased-Hole Completions. Cased-hole completions products and services include packers, flow control equipment, subsurface safety valves and intelligent completions. Packers seal the annular space between the steel production tubing and the casing. These tools control the flow of fluids in the well and protect the casing above and below from reservoir pressures and corrosive formation fluids. Flow control equipment controls and adjusts the flow of downhole fluids. A common flow control device is a sliding sleeve, which can be opened or closed to allow or limit production from a particular portion of a reservoir. Flow control can be accomplished from the surface via wireline or downhole via hydraulic or electric motor-based automated systems. Subsurface safety valves shut off all flow of fluids to the surface in the event of an emergency, thus saving the well and preventing pollution of the environment. These valves are required in substantially all offshore wells. Intelligent Completions® use real-time, remotely operated downhole systems to control the flow of hydrocarbons from one or more zones.

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     Sand Control. Sand control equipment includes gravel pack tools, sand screens and fracturing fluids. Sand control systems and pumping services are used in loosely consolidated formations to prevent the production of formation sand with the hydrocarbons.
     Wellbore Intervention. Wellbore intervention products and services are designed to protect producing assets. Intervention operations troubleshoot drilling problems and improve, maintain or restore economical production from already-producing wells. 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 Company’s 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 Company’s 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. Management’s 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. Management’s 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. O’Donnell
    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 Motorola’s 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 industry’s 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 world’s 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 Company’s 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 Company’s 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 company’s 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 company’s ongoing businesses or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s 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 company’s 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 Company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 REGISTRANT’S 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 & Poor’s 500 Stock Index and the cumulative total return on Standard & Poor’s 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
(PERFORMANCE GRAPH)
                                                                 
 
        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. Management’s 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 segment’s 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. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     Management’s 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 segment’s 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 International’s 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 Monitor’s 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 monitor’s 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 segment’s 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 Company’s 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 SEC’s 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 party’s 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, Venezuela’s 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
Management’s 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 Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s 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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
     We have audited the internal control over financial reporting of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
     A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s 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 company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of 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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Baker Hughes Incorporated
Houston, Texas
     We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 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 Company’s 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 Company’s 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 Company’s internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Houston, Texas
February 25, 2010

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Baker Hughes Incorporated
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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Baker Hughes Incorporated
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

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Baker Hughes Incorporated
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

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Baker Hughes Incorporated
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
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 customer’s 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)
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)
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 asset’s 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)
     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)
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 Company’s 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)
     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 Company’s 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 Company’s 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 segment’s 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 employee’s 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)
vesting upon the employee’s 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)
     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)
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)
     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)
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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Baker Hughes Incorporated
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)
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 entity’s 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)
     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)
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)
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)
     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)
     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)
     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 employee’s 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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Baker Hughes Incorporated
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)
     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)
     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. Plan’s 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. Plan’s 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)
 
(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. Plan’s 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 Plan’s funding position resulting from changes in the U.K. Plan’s 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 world’s 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)
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 employee’s 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 employee’s 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)
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 FCPA’s 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)
portion of the government’s 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 FCPA’s antibribery provisions related to our operations in Kazakhstan, the FCPA’s 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 management’s 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 FCPA’s 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 Company’s 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 Company’s 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 Company’s 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 Company’s 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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     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 plaintiff’s 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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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 plaintiff’s counsel’s 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 PRP’s 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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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 )   &nbs