BAKER HUGHES a GE 10K 2007 Annual report

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, 2007


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		76-0207995
(State or other jurisdiction of incorporation or organization)		(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 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.þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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 29, 2007 reported by the New York Stock Exchange) was approximately $26,845,000,000.

As of February 19, 2008, the registrant has outstanding 309,397,947 shares of common stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Registrant’s Definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 24, 2008 are incorporated by reference into Part III of this Form 10-K.

Baker Hughes Incorporated

INDEX


		Page

Part I

Item 1.	Business		2
Item 1A.	Risk Factors		16
Item 1B.	Unresolved Staff Comments		20
Item 2.	Properties		20
Item 3.	Legal Proceedings		20
Item 4.	Submission of Matters to a Vote of Security Holders		22

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
Item 6.	Selected Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		45
Item 8.	Financial Statements and Supplementary Data		48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		83
Item 9A.	Controls and Procedures		83
Item 9B.	Other Information		83

Part III

Item 10.	Directors, Executive Officers and Corporate Governance		83
Item 11.	Executive Compensation		83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		84
Item 13.	Certain Relationships and Related Transactions, and Director Independence		86
Item 14.	Principal Accountant Fees and Services		86

Part IV

Item 15.	Exhibits and Financial Statement Schedules		86
Executive Severance Plan
Annual Incentive Compensation Plan
Form of Restricted Stock Unit Agreement
Form of Performance Unit Award Agreement
Compensation Table for Named Executive Officers and Directors
Subsidiaries
Consent of Deloitte & Touche LLP
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Statement of CEO & CFO Pursuant to Rule 13a-14(b)

PART I

ITEM 1. BUSINESS

Baker Hughes Incorporated (“Baker Hughes,” “Company,” “we,” “our” or “us”) is a Delaware corporation engaged in the oilfield services industry. Baker Hughes is a major supplier of products and technology services and systems to the worldwide oil and natural gas industry, including products and services for drilling, formation evaluation, completion and production of oil and natural gas wells. We may conduct our operations through subsidiaries, affiliates, ventures and alliances.

Baker Hughes was formed in April 1987 in connection with the combination of Baker International Corporation and Hughes Tool Company. We acquired Western Atlas Inc. in a merger completed on August 10, 1998.

As used herein, “Baker Hughes,” “Company,” “we,” “our” and “us” may refer to Baker Hughes Incorporated and/or its subsidiaries. The use of these terms is not intended to connote any particular corporate status or relationships.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our Internet website at www.bakerhughes.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”).

We have adopted a Business Code of Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also required our principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct and Code of Ethical Conduct Certifications are available on the Investor Relations section of our website at www.bakerhughes.com. We will disclose on 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 Certification, Corporate Governance Guidelines and the charters of the committees referenced above are available in print at no cost to any stockholder who requests them by writing or telephoning us at the following address or telephone number:

Baker Hughes Incorporated
2929 Allen Parkway, Suite 2100
Houston, TX 77019-2118
Attention: Investor Relations
Telephone: (713) 439-8039

Information contained on or connected to our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing we make with the SEC.

We are a provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We report our results under two segments - the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions is affected by similar economic conditions. They also operate in the same markets, which include all of the major oil and natural gas producing regions of the world. We previously reported a third segment, WesternGeco, which consisted of our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger Limited (“Schlumberger”); however, on April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger.

The results of our Drilling and Evaluation segment and our Completion and Production segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

	•		The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services) divisions. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells.

	•		The Completion and Production segment consists of the Baker Oil Tools (workover, fishing and completion equipment),

Baker Petrolite (oilfield specialty chemicals) and Centrilift (electrical submersible pumps and progressing cavity pumps) divisions and the ProductionQuest (production optimization and permanent monitoring) business unit. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

For additional industry segment information for the three years ended December 31, 2007, see Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.

DRILLING AND EVALUATION SEGMENT

Baker Hughes Drilling Fluids

Baker Hughes Drilling Fluids is a major provider of drilling fluids (also called “mud”), completion fluids (also called “brines”) and fluids environmental services (also called “waste management”). Drilling fluids are an important component of the drilling process and are pumped from the surface through the drill string, exiting nozzles in the drill bit and traveling back up the wellbore where the fluids are recycled. This process cleans the bottom of the well by transporting the cuttings to the surface while also cooling and lubricating the bit and drill string. Drilling fluids are typically manufactured by mixing oil, synthetic fluids or water with barite to give them weight, which enables the fluids to hold the wellbore open and stabilize it. Additionally, the fluids control downhole pressure and seal porous sections of the wellbore. To ensure maximum efficiency and wellbore stability, chemical additives are blended by the wellsite engineer with drilling fluids to achieve particular physical or chemical characteristics. For drilling through the reservoir itself, Baker Hughes Drilling Fluids’ drill-in or completion fluids possess properties that minimize formation damage. Fluids environmental services of Baker Hughes Drilling Fluids also provides equipment and services to separate the drill cuttings from the drilling fluids and re-inject the processed cuttings into specially prepared wells, or to transport and dispose of the cuttings by other means.

Technology is very important in the selection of drilling fluids for many drilling programs, especially in deepwater, deep drilling and environmentally sensitive areas whereas cost efficiency tends to drive customer purchasing decisions in other areas. Specific opportunities for competitive differentiation include:

	•		improving drilling efficiency,

	•		minimizing formation damage, and

	•		handling and disposing of drilling fluids and cuttings in an environmentally safe manner.

Baker Hughes Drilling Fluids’ primary competitors include M-I SWACO, Halliburton Company (“Halliburton”) and Newpark Resources, Inc.

Key business drivers for Baker Hughes Drilling Fluids include the number of drilling rigs operating (especially the number of drilling programs targeting deep formations), total footage drilled, environmental regulations, as well as the current and expected future price of both oil and natural gas.

Hughes Christensen

Hughes Christensen is a leading manufacturer and supplier of drill bits, primarily Tricone^® roller cone bits and fixed-cutter polycrystalline diamond compact (“PDC”) bits, to the worldwide oil and natural gas industry. The primary objective of a drill bit is to drill a high quality wellbore as efficiently as possible.

Tricone^® Bits. Tricone^® drill bits employ either hardened steel teeth or tungsten carbide insert cutting structures mounted on three rotating cones. These bits work by crushing and shearing the formation rock as they are turned. Tricone^® drill bits have a wide application range.

PDC Bits. PDC (also known as “Diamond”) bits use fixed position cutters that shear the formation rock with a milling action as they are turned. In many softer and less variable applications, PDC bits offer higher penetration rates and a longer life than Tricone^®bits. Advances in PDC technology have expanded the application of PDC bits into harder, more abrasive formations. A rental market has developed for PDC bits as improvements in bit life and bit repairs allow a bit to be used to drill multiple wells.

The main driver of customer purchasing decisions in drill bits is the value added, usually measured in terms of savings in total operating costs per foot drilled. Specific opportunities for competitive differentiation include:

	•		improving the rate of penetration,

	•		extending bit life and bit reliability, and

	•		selecting the optimal bit for each section to be drilled.

Hughes Christensen’s primary competitors in the oil and natural gas drill bit market include Smith International, Inc. (“Smith”), Grant Prideco, Inc. and Halliburton.

Key business drivers for Hughes Christensen include the number of drilling rigs operating, total footage drilled, type of well drilled (vertical, deviated, horizontal or extended reach), drilling rig rental costs, as well as the current and expected future price of both oil and natural gas.

INTEQ

INTEQ is a leading supplier of drilling and evaluation services, which include directional drilling, measurement-while-drilling (“MWD”) and logging-while-drilling (“LWD”) services.

Directional Drilling. Directional drilling services are used to guide a drill string along a predetermined path to drill a wellbore to optimally recover hydrocarbons from the reservoir. These services are used to accurately drill vertical wells, deviated or directional wells (which deviate from vertical by a planned angle and direction), horizontal wells (which are sections of wells drilled perpendicular or nearly perpendicular to vertical) and extended reach wells.

INTEQ is a leading supplier of both conventional and rotary based directional drilling systems. Conventional directional drilling systems employ a downhole motor that turns the drill bit independently of drill string rotation from the surface. Placed just above the bit, a steerable motor assembly has a bend in its housing that is oriented to steer the well’s course. During the “rotary” mode, the entire drill string is rotated from the surface, negating the effect of this bend and causing the bit to drill on a straight course. During the “sliding” mode, drill string rotation is stopped and a “mud” motor (which converts hydraulic energy from the drilling fluids being pumped through the drill string into rotational energy at the bit) allows the bit to drill in the planned direction by orienting its angled housing, gradually guiding the wellbore through an arc.

INTEQ was a pioneer and is a leader in the development and use of automated rotary steerable technology. In rotary steerable environments, the entire drill string is turned from the surface to supply energy to the bit. Unlike conventional systems, INTEQ’s AutoTrak^® rotary steerable system changes the trajectory of the well using three pads that push against the wellbore from a non-rotating sleeve and is controlled by a downhole guidance system.

INTEQ’s AutoTrak^® Xtreme^® system combines conventional mud motor technology with rotary steerable technology to provide directional control and improved rate of penetration.

Measurement-While-Drilling. Directional drilling systems need real-time measurements of the location and orientation of the bottom-hole assembly to operate effectively. INTEQ’s MWD systems are downhole tools that provide this directional information, which is necessary to adjust the drilling process and guide the wellbore to a specific target. The AutoTrak^® rotary steerable system has these MWD systems built in, allowing the tool to automatically alter its course based on a planned trajectory.

Logging-While-Drilling. LWD is a variation of MWD in which the LWD tool gathers information on the petrophysical properties of the formation through which the wellbore is being drilled. Many LWD measurements are the same as those taken via wireline; however, taking them in real-time often allows for greater accuracy, as measurements occur before any damage has been sustained by the reservoir as a result of the drilling process. Real-time measurements also enable “geo-steering” where geological markers identified by LWD tools are used to guide the bit and assure placement of the wellbore in the optimal location.

In both MWD and LWD systems, surface communication with the tool is achieved through mud-pulse telemetry, which uses pulse signals (pressure changes in the drilling fluids traveling through the drill string) to communicate the operating conditions and location of the bottom-hole assembly to the surface. The information transmitted is used to maximize the efficiency of the drilling process, update and refine the reservoir model and steer the well into the optimal location in the reservoir.

As part of INTEQ’s mud logging services, engineers monitor the interaction between the drilling fluid and the formation and perform laboratory analysis of drilling fluids and examinations of the drill cuttings to detect the presence of hydrocarbons and identify the different geological layers penetrated by the drill bit.

The main drivers of customer purchasing decisions in these areas are the value added by technology and the reliability and durability of the tools used in these operations. Specific opportunities for competitive differentiation include:

	•		the sophistication and accuracy of measurements,

	•		the efficiency of the drilling process (measured in cost per foot drilled), rate of penetration, and reduction of non-productive time,

	•		the reliability of equipment,

	•		the optimal placement of the wellbore in the reservoir, and

	•		the quality of the wellbore.

INTEQ’s primary competitors in drilling and evaluation services include Halliburton, Schlumberger and Weatherford International Ltd. (“Weatherford”).

Key business drivers for INTEQ include the number of drilling rigs operating, the total footage drilled, the mix of conventional and rotary steerable systems used, technological sophistication of and type of wells being drilled (vertical, deviated, horizontal or extended reach), as well as the current and expected future price of both oil and natural gas.

Baker Atlas

Baker Atlas is a leading provider of formation evaluation and wireline completion and production services for oil and natural gas wells.

Formation Evaluation. Formation evaluation involves measuring and analyzing specific physical properties of the rock (petrophysical properties) in the immediate vicinity of a wellbore to determine an oil or natural gas 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 providing a direct measure of permeability. At the surface, measurements are recorded digitally and can be displayed on a continuous graph, or “well log,” which shows how each parameter varies along the length of the wellbore. Formation evaluation tools can also be used to record formation pressures and take samples of formation fluids to be further evaluated on the surface.

Formation evaluation instrumentation can be run in the well in several ways and at different times over the life of the well. The two most common methods of data collection are wireline logging (performed by Baker Atlas) and LWD (performed by INTEQ). Wireline logging is conducted by pulling or pushing instruments through the wellbore after it is drilled, while LWD instruments are attached to the drill string and take measurements while the well is being drilled. Wireline logging measurements can be made before the well’s protective steel casing is set (open hole logging) or after casing has been set (cased hole logging). Baker Atlas also offers geophysical data interpretation services which help the operator interpret the petrophysical properties measured by the logging instruments and make inferences about the formation, presence and quantity of hydrocarbons. This information is used to determine the next steps in drilling and completing the well.

Wireline Completion and Production Services. Wireline completion and production services include using wireline instruments to evaluate well integrity, perform mechanical intervention and perform cement evaluations. Wireline instruments can also be run in producing wells to perform production logging. Baker Atlas (and Baker Oil Tools) also provide perforating services, which involve puncturing a 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.

Baker Atlas’ services allow oil and natural gas companies to define, manage and reduce their exploration and production risk. As such, the main driver of customer purchasing decisions is the value added by formation evaluation and wireline completion and production services. Specific opportunities for competitive differentiation include:

	•		the efficiency of data acquisition,

	•		the sophistication and accuracy of measurements,

	•		the ability to interpret the information gathered to quantify the hydrocarbons producible from the formation,

	•		the efficiency of providing wireline completion and production services at the wellsite, and

	•		the ability to differentiate services that can run exclusively or more efficiently on wireline from services that can run on either wireline or drill pipe.

Baker Atlas’ primary formation evaluation and wireline completion and perforating competitors include Schlumberger, Halliburton and Weatherford.

Key business drivers for Baker Atlas include the number of drilling and workover rigs operating, as well as the current and expected future price of both oil and natural gas.

COMPLETION AND PRODUCTION SEGMENT

Baker Oil Tools

Baker Oil Tools is a world leader in wellbore construction, cased-hole completions, sand control and wellbore intervention solutions. The economic success of a well largely depends on how the well is completed. A successful completion ensures and optimizes the efficient and safe production of oil and natural gas to the surface. Baker Oil Tools’ completion systems are matched to the formation and reservoir for optimum production and can employ a variety of products and services.

Wellbore Construction.Wellbore completion products and services include liner hangers, multilateral completion systems and expandable metal technology.

Liner hangers suspend a section of steel casing (also called a liner) inside the bottom of the previous section of casing. The liner 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.

Sand Control.Sand control equipment includes gravel pack tools, sand screens and fracturing fluids. Sand control systems and pumping services are used in loosely consolidated formations to prevent the production of formation sand with the hydrocarbons.

Wellbore Intervention.Wellbore intervention products and services are designed to protect producing assets. Intervention operations troubleshoot drilling problems and improve, maintain or restore economical production from already-producing wells. In this area, Baker Oil Tools’ offerings range from service tools and inflatable products to conventional and through-tubing fishing systems, casing exits, wellbore cleaning and temporary abandonment.

Service tools function as surface-activated, downhole sealing and anchoring devices to isolate a portion of the wellbore during repair or stimulation operations. Service tool applications range from treating and cleaning to testing components from the wellhead to the perforations. Service tools also refer to tools and systems that are used for temporary or permanent well abandonment.

Inflatable packers expand to set in pipe that is much larger than the outside diameter of the packer itself, so it can run through a restriction in the well and then set in the larger diameter below. Inflatable packers also can be set in “open hole” whereas conventional tools only can be set inside casing. Through-tubing inflatables enable remedial operations in producing wells. Significant cost savings result from lower rig requirements and the ability to intervene in the well without having to remove the completion.

Fishing tools and services are used to locate, dislodge and retrieve damaged or stuck pipe, tools or other objects from inside the wellbore, often thousands of feet below the surface.

Wellbore cleaning systems remove post-drilling debris to help ensure trouble-free well testing, completion and optimum production for the life of the well.

Casing exit systems are used to “sidetrack” new wells from existing ones, to provide a cost-effective method of tapping previously unreachable reserves.

The main drivers of customer purchasing decisions in wellbore construction, cased-hole completions, sand control and wellbore intervention are superior wellsite service execution and value-adding technologies that improve production rates, protect the reservoir from damage and reduce cost. Specific opportunities for competitive differentiation include:

	•		engineering and manufacturing superior-quality products and providing solutions with a proven ability to reduce well construction costs,

	•		enhancing production and ultimate recovery,

	•		minimizing risks, and

	•		providing reliable performance over the life of the well, particularly in harsh environments and for critical wells.

Baker Oil Tools’ primary competitors in wellbore construction, cased-hole completions and sand control include Halliburton, Schlumberger and Weatherford. Its primary competitors in wellbore intervention include Weatherford and Smith.

Key business drivers for Baker Oil Tools include the number of drilling and workover rigs operating, the relative complexity of the wells drilled and completed, as well as the current and expected future price of both oil and natural gas.

Baker Petrolite

Baker Petrolite is a leading provider of specialty chemicals to the oil and gas industry. The division also supplies specialty chemicals to a number of industries including refining, pipeline transportation, petrochemical, agricultural and iron and steel manufacturing and provides polymer-based products to a broad range of industrial and consumer markets. Through its Pipeline Management Group, Baker Petrolite also offers a variety of products and services for the pipeline transportation industry.

Oilfield Chemicals. Baker Petrolite provides oilfield chemical programs for drilling, well stimulation, production, pipeline transportation and maintenance programs. Its products provide measurable increases in productivity, decreases in operating and maintenance cost and solutions to environmental problems. Examples of specialty oilfield chemical programs include emulsion breakers and chemicals which inhibit the formation of paraffin, scale, hydrates and other well performance issues or problems.

Hydrate inhibitors – Natural gas hydrates are solid ice-like crystals that form in production flowlines and tubing and cause shutdowns and the need for system maintenance. Subsea wells and flowlines, particularly in deepwater environments, are especially susceptible to hydrates.

Paraffin inhibitors – The liquid hydrocarbons produced from many oil and natural gas reservoirs become unstable soon after leaving the formation. Changing conditions, including decreases in temperature and pressure, can cause certain hydrocarbons in the produced fluids to crystallize and deposit on the walls of the well’s tubing, flow lines and surface equipment. These deposits are commonly referred to as paraffin. Baker Petrolite offers solvents that remove the deposits, as well as inhibitors that prevent new deposits from forming.

Scale inhibitors – Unlike paraffin deposits that originate from organic material in the produced hydrocarbons, scale deposits come from mineral-based contaminants in water that are produced from the formation as the water undergoes changes in temperature or pressure. Similar to paraffin, scale deposits can clog the production system. Treatments prevent and remove deposits in production systems.

Corrosion inhibitors – Another problem caused by water mixed with downhole hydrocarbons is corrosion of the well’s tubulars and other production equipment. Corrosion can also be caused by dissolved hydrogen sulfide (“H₂S”) gas, which reacts with the iron in tubulars, valves and other equipment, potentially causing failures and leaks. Additionally, the reaction creates iron sulfide, which can impair treating systems and cause blockages. Baker Petrolite offers a variety of corrosion inhibitors and H₂S scavengers.

Emulsion breakers – Water and oil typically do not mix, but water present in the reservoir and co-produced with oil can often become emulsified, or mixed, causing problems for oil and natural gas producers. Baker Petrolite offers emulsion breakers that allow the water to be separated from the oil.

Refining, Industrial and Other Specialty Chemicals. For the refining industry, Baker Petrolite offers various process and water treatment programs, as well as finished fuel additives. Examples include programs to remove salt from crude oil and to control corrosion in processing equipment and environmentally friendly cleaners that decontaminate refinery equipment and petrochemical vessels at a lower cost than other methods. Baker Petrolite also provides chemical technology solutions to other industrial markets throughout the world, including petrochemicals, fuel additives, plastics, imaging, adhesives, steel and crop protection.

Pipeline Management. Baker Petrolite’s Pipeline Management Group (“PMG”) offers a variety of products and services for the pipeline transportation industry. To improve efficiency, Baker Petrolite offers custom turnkey cleaning programs that combine chemical treatments with brush and scraper tools that are pumped through the pipeline. Efficiency can also be improved by adding polymer-based drag reduction agents to reduce the slowing effects of friction between the pipeline walls and the fluids within, thus increasing throughput and pipeline capacity. Additional services allow pipelines to operate more safely. These include inspection and internal corrosion assessment technologies, which physically confirm the structural integrity of the pipeline. In addition, PMG’s flow-modeling capabilities can identify high-risk segments of a pipeline to ensure proper mitigation programs are in place.

The main driver of customer purchasing decisions in specialty chemicals is superior application of technology and service delivery. Specific opportunities for competitive differentiation include:

	•		higher levels of production or throughput,

	•		lower maintenance costs and frequency,

	•		lower treatment costs and treatment intervals, and

	•		successful resolution of environmental issues.

Baker Petrolite’s primary competitors include Champion Technologies, Inc., Nalco Holding Company and Smith.

Key business drivers for Baker Petrolite include oil and natural gas production levels, the number of producing wells, total liquids production, and the current and expected future price of both oil and natural gas.

Centrilift

Centrilift is a leading manufacturer and supplier of electrical submersible pump systems (“ESPs”) and progressing cavity pump systems (“PCPs”).

Electrical Submersible Pump Systems. ESPs lift large quantities of oil or oil and water from wells that do not flow under their own pressure. These “artificial lift” systems consist of a centrifugal pump and electric motor installed in the wellbore, armored electric cabling to provide power to the downhole motor and a variable speed controller at the surface. Centrilift designs, manufactures, markets and installs all the components of ESP systems and also offers modeling software to size ESPs and simulate operating performance. ESPs may be used in both onshore and offshore wells. The range of appropriate application of ESP systems is expanding as technology and reliability enhancements have improved ESP system performance in harsher environments and marginal reservoirs.

Progressing Cavity Pump Systems. PCPs are a form of artificial lift comprised of a downhole progressing cavity pump powered by either a downhole electric motor or a rod turned by a motor on the surface. PCP systems are preferred when the fluid to be lifted is viscous or when the volume is significantly less than could be economically lifted with an ESP system.

The main drivers of a customer purchasing decision in an artificial lift include the depth of the well, the volume of the fluid, the physical and chemical properties of the fluid as well as the capital and operating cost over the run life of the system. Specific opportunities for competitive differentiation include:

	•		the ability to lift fluids of differing physical properties and chemical compositions,

	•		system reliability and run life,

	•		the ability of the system to optimize production,

	•		operating efficiency, and

	•		service delivery.

Centrilift’s primary competitors in the ESP market include Schlumberger and John Wood Group PLC (ESP Inc.). In the PCP market, the primary competitors include Weatherford, Robbins & Myers, Inc. and Kudu Industries, Inc.

Key business drivers for Centrilift include oil production levels, as well as the current and expected future price of oil, the volume of water produced in mature basins and gas dewatering in coal bed methane and other gas wells.

ProductionQuest

The ProductionQuest business unit is a provider of permanent monitoring systems and chemical automation systems.

Permanent Monitoring Systems. Permanent downhole gauges are used in oil and gas wells to measure temperature, pressure, flow and other parameters in order to monitor well production as well as to confirm the integrity of the completion and production equipment in the well. ProductionQuest is a leading provider of electronic gauges including the engineering, application and field services necessary to complete an installation of a permanent monitoring system. In addition, they provide chemical injection line installation and services for treating wells for corrosion, paraffin, scale and other well performance problems. They also provide fiber optic based permanent downhole gauge technology for measuring pressure, temperature and distributed temperature. The benefits of fiber optic sensing include reliability, high temperature properties and the ability to obtain distributed readings.

Chemical Automation Systems. Chemical automation systems remotely monitor chemical tank levels that are resident in producing field locations for well treatment or production stimulation as well as continuously monitor and control chemicals being injected in individual wells. By using these systems, a producer can ensure proper chemical injection through real-time monitoring and can also remotely modify the injection parameters to ensure optimized production.

The main drivers of customer purchasing decisions for both permanent monitoring and chemical automation include application engineering expertise, ability to integrate a complete system, product reliability, functionality and local field support. Specific opportunities for competitive differentiation include:

	•		the ability to provide application engineering and economic return analysis,

	•		product innovation,

	•		gauge measurement accuracy,

	•		product life and performance, and

	•		installation and service capabilities.

ProductionQuest’s primary competitors include Schlumberger, Halliburton and Weatherford.

Key business drivers for ProductionQuest include the level of oil and gas prices, total daily oil and gas production and capital spending for critical wells (offshore, subsea, high production onshore and remotely located onshore).

WESTERNGECO

WesternGeco was a seismic venture in which we owned 30% and Schlumberger owned 70%. On April 28, 2006, we sold our 30% interest to Schlumberger for $2.4 billion in cash and recorded a pre-tax gain of $1,743.5 million ($1,035.2 million after-tax).

For additional information related to WesternGeco, see the “Related Party Transactions” section in Item 7 and Note 5 of the Notes to Consolidated Financial Statements in Item 8, both contained herein.

MARKETING, COMPETITION AND ECONOMIC CONDITIONS

We market our products and services on a product line basis primarily through our own sales organizations, although certain of our products and services are marketed through independent distributors, commercial agents, licensees or sales representatives. Over the past several years, we have significantly reduced the number of commercial agents that we use to conduct our business. In the markets in which we formerly utilized commercial agents, we have established our own marketing operations and are continuing to build direct relationships with our customers. We ordinarily provide technical and advisory services to assist in our customers’ use of our products and services. Stock points and service centers for our products and services are located in areas of drilling and production activity throughout the world.

Our products and services are sold in highly competitive markets, and revenues and earnings can be affected by changes in competitive prices, fluctuations in the level of drilling, workover and completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and governmental regulations. We compete with the oil and natural gas industry’s largest diversified oilfield services providers, as well as many small companies. We believe that the principal competitive factors in our industries are product and service quality, availability and reliability, health, safety and environmental standards, technical proficiency and price.

Further information is contained in “Item 7. 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, both contained herein.

INTERNATIONAL OPERATIONS

We operate in over 90 countries around the world and our corporate headquarters is in Houston, Texas. We have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), the United Kingdom (Scotland and Northern Ireland), Germany (Celle), and South America (Venezuela and Argentina). As of December 31, 2007, we had approximately 35,800 employees of which approximately 57% work outside the United States.

The business operations of our divisions are organized around four primary geographic regions: North America, Latin America, Middle East and Asia Pacific, and Europe, Africa, Russia and the Caspian. Each region has a council comprised of regional vice presidents from each division as well as representatives from various functions such as human resources, legal including compliance, marketing, finance and treasury, and health, safety and environmental. The regional vice presidents report directly to each division president. Through this structure, we have placed our management closer to the customer, 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 contained 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, 2007, see Note 16 of the Notes to Consolidated Financial Statements in Item 8 herein.

We have followed a policy of seeking patent and trademark protection both inside and outside the United States for products and methods that appear to have commercial significance. We believe our patents and trademarks to be adequate for the conduct of our business, and aggressively pursue protection of our patents against patent infringement worldwide. Although patent and trademark protection is important to our business and future prospects, we consider the reliability and quality of our products and the technical skills of our personnel to be more important. No single patent or trademark is considered to be critical to our business.

SEASONALITY

Our operations can be affected by seasonal weather patterns and natural phenomena, which can temporarily affect the delivery and performance of our products and services, as well as customer’s 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 operations,

	•		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 could be subject to rising costs. We have not experienced significant shortages of these materials and normally do not carry inventories of such materials in excess of those reasonably required to meet our production schedules. We do not expect significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

EMPLOYEES

On December 31, 2007, we had approximately 35,800 employees, as compared with approximately 34,600 employees on December 31, 2006. Approximately 3,020 of these employees are represented under collective bargaining agreements or similar-type labor arrangements, of which the majority are outside the U.S. Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole. We believe that our relations with our employees are good.

EXECUTIVE OFFICERS

The following table shows, as of February 21, 2008, the name of each of our executive officers, together with his age and all offices presently held.


Name	Age

Chad C. Deaton		55	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.

Alan R. Crain		56	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.

Peter A. Ragauss		50	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.

David H. Barr		58	Group President of Completion and Production since 2007 and Vice President of the Company since 2000. Group President of Drilling and Evaluation from 2005 to 2007. President of Baker Atlas from 2000 to 2005. Vice President, Supply Chain Management, of Cooper Cameron from 1999 to 2000. Mr. Barr also held the following positions with the Company: Vice President, Business Process Development, from 1997 to 1998 and the following positions with Hughes Tool Company/Hughes Christensen: Vice President, Production and Technology, from 1994 to 1997; Vice President, Diamond Products, from 1993 to 1994; Vice President, Eastern Hemisphere Operations, from 1990 to 1993 and Vice President, North American Operations, from 1988 to 1990. Employed by the Company in 1972.

Martin S. Craighead		48	Group President of Drilling and Evaluation since 2007 and Vice President of the Company since 2005. 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.

Didier Charreton		44	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.

Christopher P. Beaver		50	Vice President of the Company and President of Baker Oil Tools since 2005. Vice President of Finance for Baker Petrolite from 2002 to 2005; Director of Finance and Controller at INTEQ from 1999 to 2002; Controller at Hughes Christensen from 1994 to 1999. Various accounting and finance positions at Hughes Christensen in the Eastern Hemisphere from 1985 to 1994. Employed by the Company in 1985.


Name	Age

Paul S. Butero		51	Vice President of the Company since 2005 and President of INTEQ since 2007. President of Baker Atlas from 2006 to 2007. President of Hughes Christensen from 2005 to 2006. Vice President, Marketing, of Hughes Christensen from 2001 to 2005 and as Region Manager for various Hughes Christensen areas (both in the United States and the Eastern Hemisphere) from 1989 to 2001. Employed by the Company in 1981.

Stephen K. Ellison		49	Vice President of the Company and President of Baker Atlas since 2007. Vice President, Middle East, Asia Pacific Region for Baker Atlas from 2005 to 2007; Asia Pacific Region Manager, Baker Atlas from 2001 to 2005 and Asia Pacific Region Operations Manager, Baker Atlas from 2000 to 2001. Employed by the Company in 1979.

Alan J. Keifer		53	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		56	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.

Nelson Ney		44	Vice President of the Company and President of Centrilift since 2007. Operations Vice President, Europe, Africa, Russia and the Caspian Region for Hughes Christensen from 2006 to 2007; Operations Vice President, Centrilift Latin America Region from 2005 to 2006; General Manager, Centrilift Latin America operations from 2004 to 2005 and Regional Manager, Hughes Christensen Latin America operations from 2001 to 2004. Employed by the Company in 1990.

John A. O’Donnell		59	Vice President of the Company since 1998 and President of Baker Petrolite Corporation since 2005. President of Baker Hughes Drilling Fluids from 2004 to 2005. Vice President, Business Process Development of the Company from 1998 to 2002; Vice President, Manufacturing, of Baker Oil Tools from 1990 to 1998 and Plant Manager of Hughes Tool Company from 1988 to 1990. Employed by the Company in 1975.

Gary G. Rich		49	Vice President of the Company and President of Hughes Christensen since 2006. Vice President Marketing, Drilling and Evaluation for INTEQ from 2005 to 2006. Region Manager for INTEQ from 2001 to 2005; Director of Marketing for Hughes Christensen from 1998 to 2001 and served in various marketing and finance positions for the Company from 1987 to 1998. Employed by the Company in 1987.

Richard L. Williams		52	Vice President of the Company and President of Baker Hughes Drilling Fluids since 2005. Vice President, Eastern Hemisphere Operations, Baker Oil Tools from March 2005 to May 2005. Worldwide Operations Vice President, INTEQ from 2004 to 2005; Vice President Eastern Hemisphere, INTEQ from 2003 to 2004 and Vice President Western Hemisphere, INTEQ from 2001 to 2003. Employed by the Company in 1975.

There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

We are committed to the health and safety of people, protection of the environment and compliance with laws, regulations and our policies. Our past and present operations include activities that are subject to domestic (including U.S. federal, state and local) and international regulations with regard to air and water quality and other environmental matters. We believe we are in substantial compliance with these regulations. Regulation in this area continues to evolve, and changes in standards of enforcement of existing regulations, as well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement or replace equipment or facilities or to change or discontinue present methods of operation.

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. Such accruals are recorded when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.

During the year ended December 31, 2007, we spent $35.2 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 2008, we expect to spend approximately $38 million to comply with Environmental Regulations. During the year ended December 31, 2007, we incurred $7.9 million in capital expenditures for environmental control equipment, and we estimate we will incur approximately $15 million during 2008. In addition, we estimate we will incur approximately $19 million in capital expenditures for the relocation of an existing plant in the U.K. to comply with local environmental regulations. Depending on the resolution of environmental permitting, up to $13 million may be spent in 2008 and the remainder in 2009. Based upon current information, we believe that our compliance with Environmental Regulations will not have a material adverse effect upon our capital expenditures, earnings or competitive position because we have either established adequate reserves or our cost for that compliance is not expected to be material to our consolidated financial statements.

The Comprehensive Environmental Response, Compensation and Liability Act (known as “Superfund” or “CERCLA”) imposes liability for the release of a “hazardous substance” into the environment. Superfund liability is imposed without regard to fault, even if the waste disposal was in compliance with laws and regulations. We have been identified as a potentially responsible party (“PRP”) in remedial activities related to various Superfund sites, and we accrue our share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site. With the joint and several liability imposed under Superfund, a PRP may be required to pay more than its proportional share of such costs.

We have been identified as a PRP at various Superfund sites discussed below. The United States Environmental Protection Agency (the “EPA”) and appropriate state agencies supervise investigative and cleanup activities at these sites. For the year ended December 31, 2007, we paid $0.1 million in Superfund costs and have accrued an additional $5.3 million related to these sites. Payments made in 2007 are in addition to amounts previously paid in settlements, cash calls or other Superfund costs, and these ongoing contributions reduce our financial liability for the total site cleanup costs shown below. When used in the descriptions of the sites that follow, the word de minimis refers to the smallest PRPs, whose contribution rate is usually less than 1%.

	(a)		In 1999, Baker Oil Tools, Baker Petrolite and predecessor entities of Baker Petrolite were named as PRPs by the State of California’s Department of Toxic Substances Control for the Gibson site in Bakersfield, California. Remediation consisting of extensive soil excavation and removal is now complete at a cost of approximately $5 million, with remaining costs estimated at less than $1 million. Our combined volume allocation is 1.6% for liquids and 0.4% for solids.

	(b)		In 2001, a Hughes Christensen predecessor, Baker Oil Tools, INTEQ and one of our former subsidiaries were named as PRPs in the Force Road State Superfund site located in Brazoria County, Texas. The Texas Commission on Environmental Quality (“TCEQ”) is overseeing the investigation and remediation at the Force Road site. We participate as a member of the steering and technical committees to effectively manage the project because our volumetric contribution is currently estimated at approximately 76%. The investigation phase of the project is essentially complete and the results indicate that the extent of the groundwater contamination is less than originally estimated. These results along with new surveys indicate little to no offsite impact. We believe that after the most effective remedial alternatives are identified, the remedial costs could be less than $10 million. An accurate calculation of site remediation costs will be available once the Remedial Action Plan is developed, which will occur during early 2008. $1.8 million was raised from the de minimis settlement process, which is now complete.

	(c)		In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and several of our former subsidiaries were identified as PRPs for the Malone site located on Campbell Bayou Road in Texas City, Texas. The EPA oversees the investigation and remediation of the Malone site and has engaged in emergency removal actions. The investigation is complete and remedial alternatives have been developed and submitted to the EPA for evaluation. The EPA has concluded that the remaining costs for the remedial action are $52.8 million. Along with the EPA oversight costs, project management fees and other expenses, the total outstanding project costs are not expected to exceed $72 million. Our contribution was recently adjusted downward and is now 1.26%. A lawsuit filed by the current owners of the site and a related entity against the PRP Group (Malone Cooperating Parties) seeking recovery of certain alleged damages was settled at a cost of $1.2 million, and included arrangements for the eventual transfer of the property to a conservation organization or other non-profit entity.

	(d)		In 2003, we were identified as a de minimis PRP by the EPA for the Operating Industries, Inc. Superfund site in Monterrey Park, California. A settlement offer to all remaining de minimis parties has been repeatedly delayed. The EPA and Steering Committee have incurred approximately $345 million and expect an additional $367 million in cleanup costs. Information provided by the EPA in 2007 indicates that our contribution is 0.092%, although our ultimate liability has yet to be negotiated and may include a premium for early settlement.

	(e)		In 2003, Baker Petrolite was notified by the EPA of their potential involvement at the Cooper Drum Superfund site located in South Gate, California. We responded to an additional inquiry from the EPA in 2005. At this time, the estimate for comprehensive cleanup costs is approximately $20 million but the extent of our responsibility for these costs is not yet known.

	(f)		In 2006, we were one of five PRPs to receive an information request from the EPA regarding the Washington County Lead District Superfund site, a federal Superfund located in Washington County, Missouri. We have responded to the EPA regarding our involvement with two of the six mines listed in the information request. A preliminary screening and removal action has been completed by the EPA to evaluate the impacts of lead and other heavy metals on the soil and groundwater in the area. In late 2007, the site was proposed for inclusion on the National Priorities list. There has been no formal assignment of responsibility and an estimate of potential cleanup costs has not been developed; therefore, we are unable to estimate the potential cost to the Company.

	(g)		In 2006, Baker Petrolite received a General Notice of Potential Liability letter from the EPA concerning the RRG/Clayton Chemical Superfund site in Sauget, Illinois and its impact on the adjacent Sauget Area 2 Groundwater Superfund site. We have participated in cleanup activities at the Clayton site as a small party with an allocation just over the de minimis level. Our known costs are approximately 0.78% of the estimated remedy cost of $5.2 million. However, our ultimate liability may now include some responsibility for the downgradient groundwater cleanup at the Sauget Area 2 Groundwater Superfund site; however, sufficient information is not available to estimate the additional potential cost to the Company.

	(h)		In 2006, a settlement demand was received from the PRP Group for the Pulvair Superfund site located in Millington, Tennessee for waste sent to the site by Milchem, a predecessor to Baker Hughes Drilling Fluids. The matter has not yet been resolved; however, it is expected to be settled at a cost of less than $0.2 million.

In addition to the sites mentioned above, there are six Superfund sites where we have ongoing obligations. The emergency removal actions and subsequent remedial work at most of these sites has been completed and remaining operations are limited to groundwater recovery and/or monitoring. The monitoring phase can continue for up to 30 years. Our aggregate cost for these sites is estimated to be $0.3 million over this period of time.

While PRPs in Superfund actions have joint and several liability for all costs of remediation, it is not possible at this time to quantify our ultimate exposure because some of the projects are either in the investigative or early remediation stage, 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 described above are likely to have a material adverse effect on our consolidated financial statements because we have recorded adequate reserves to cover the estimate we presently believe will be our ultimate liability in the matter. Further, other PRPs involved in the sites have substantial assets and may reasonably be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage or contractual indemnities from third parties to cover a portion of or the ultimate liability.

We are subject to various other governmental proceedings and regulations, including foreign regulations, relating to environmental matters, but we do not believe that any of these matters is likely to have a material adverse effect on our consolidated financial statements. We continue to focus on reducing future environmental liabilities by maintaining appropriate company standards and improving our assurance programs. See Note 15 of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of environmental matters.

“Environmental Matters” contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Exchange Act (each a “Forward-Looking Statement”). The words “will,” “believe,” “to be,” “expect,” “estimate” and similar expressions are intended to identify forward-looking statements. Our expectations regarding our compliance with Environmental Regulations and our expenditures to comply with Environmental Regulations, including (without limitation) our capital expenditures for environmental control equipment, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which may be affected by the following factors: changes in Environmental Regulations; a material change in our allocation or other unexpected, adverse outcomes with respect to sites where we have been named as a PRP, including (without limitation) the Superfund sites described above; the discovery of new sites of which we are not aware and where additional expenditures may be required to comply with Environmental Regulations; an unexpected

discharge of hazardous materials in the course of our business or operations; a catastrophic event causing discharges into the environment; or an acquisition of one or more new businesses.

ITEM 1A. RISK FACTORS

An investment in our common stock involves various risks. When considering an investment in our Company, one should consider carefully all of the risk factors described below, as well as other information included and incorporated by reference in this report. 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 and the future value of the hydrocarbon reserves. Their evaluation of the future value is based, in part, on their expectations for global demand, global supply and other factors that influence oil and natural gas prices. The key risk factors currently influencing the worldwide oil and natural gas markets are discussed below.

Demand for oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.

Growth in worldwide demand for oil and natural gas, as well as the demand for our services, is highly correlated with global economic growth, and in particular by the economic growth of countries such as the U.S. and China, who are significant users of oil and natural gas. Increases in global economic activity, particularly in China and developing Asia, create more demand for oil and natural gas and higher oil and natural gas prices. A slowing of global economic growth, and in particular in the U.S. or China, will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower prices and adversely impact the demand for our services. In addition, demand for hydrocarbons could be impacted by environmental regulation targeting reduction of greenhouse gas emissions including the cost for Carbon Capture and Sequestration.

Volatility of oil and natural gas prices can adversely affect demand for our products and services.

Volatility in oil and natural gas prices can also impact our customers’ activity levels and spending for our products and services. While current energy prices are important contributors to positive cash flow for our customers, expectations about future prices and price volatility are generally more important for determining future spending levels. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our results of operations.

Supply of oil and natural gas is subject to factors beyond our control, which may adversely affect our operating results.

Productive capacity for oil and natural gas is dependent on our customers’ decisions to develop and produce oil and natural gas reserves. The ability to produce oil and natural gas can be affected by the number and productivity of new wells drilled and completed, as well as the rate of production and resulting depletion of existing wells. Advanced technologies, such as horizontal drilling, improve total recovery but also result in a more rapid production decline.

Access to prospects and capital are also important to our customers. Access to prospects may be limited because host governments do not allow access to the reserves or because another oil and natural gas exploration company owns the rights to develop the prospect. Access to capital is dependent on our customers’ ability to access the funds necessary to develop economically attractive projects based on their expectations of future energy prices, required investments and resulting returns. Government regulations and the costs incurred by oil and natural gas exploration companies to conform to and comply with government regulations, may also limit the quantity of oil and natural gas that may be economically produced.

Supply can be interrupted by a number of factors including political instability, civil unrest, labor issues, terrorist attacks, war or military activity. Key oil producing countries which could be subject to supply interruptions include, but are not limited to, Saudi Arabia, Iraq and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela. The impact of supply disruptions on oil and

natural gas prices and oil and natural gas price volatility is tempered by the size and expected duration of the disruption relative to the spare productive capacity at the time of the disruption.

Supply can also be impacted by the degree to which individual Organization of Petroleum Exporting Countries (“OPEC”) nations and other large oil and natural gas producing countries, including, but not limited to, Norway and Russia, are willing and able to control production and exports of oil, to decrease or increase supply and to support their targeted oil price while meeting their market share objectives. Any of these factors could affect the supply of oil and natural gas and could have a material adverse effect on our results of operations.

The worldwide oil and natural gas industry is subject to geopolitical and terrorism risks.

Geopolitical risks and terrorist activity continue to grow in several key countries where the Company does business. These risks could lead to a loss of investment in the country as well as a disruption in business activities.

Spare productive capacity and future demand impact our operations.

Oil and natural gas storage inventory levels are an indicator of the relative balance between supply and demand. High or increasing storage or inventories generally indicate that supply is exceeding demand and that energy prices are likely to soften. Low or decreasing storage or inventories are an indicator that demand is growing faster than supply and that energy prices are likely to rise. Measures of maximum productive capacity compared to demand (“spare productive capacity”) are also an important factor influencing energy prices and spending by oil and natural gas exploration companies. When spare productive capacity is low compared to demand, energy prices tend to be higher and more volatile reflecting the increased vulnerability of the entire system to disruption.

Seasonal and adverse weather conditions adversely affect demand for our services and operations.

Weather can also have a significant impact on demand as consumption of energy is seasonal and any variation from normal weather patterns, cooler or warmer summers and winters, can have a significant impact on demand. Adverse weather conditions, such as hurricanes in the Gulf of Mexico, may interrupt or curtail our operations, or our customers’ operations, cause supply disruptions and result in a loss of revenue and damage to our equipment and facilities, which may or may not be insured.

Risk Factors Related to Our Business

Our expectations regarding our business are affected by the following risk factors and the timing of any of these risk factors:

We operate in a highly competitive environment, which may adversely affect our ability to succeed.

We operate in a highly competitive environment for marketing oilfield services and securing equipment and trained personnel. Our ability to continually provide competitive products and services can impact our ability to maintain or increase prices for our products and services, maintain market share and negotiate acceptable contract terms with our customers. In order to be competitive, we must provide new technologies, and reliable products and services that perform as expected and that create value for our customers. Our ability to maintain or increase prices for our products and services is in part dependent on the industry’s capacity relative to customer demand, and on our ability to differentiate the value delivered by our products and services from our competitor’s products and services. In addition, our ability to negotiate acceptable contract terms and conditions with our customers, especially state-owned national oil companies, our ability to manage warranty claims and our ability to effectively manage our commercial agents can also impact our results of operations.

Managing development of competitive technology and new product introductions on a forecasted schedule and at forecasted costs can impact our financial results. Development of competing technology that accelerates the obsolescence of any of our products or services can have a detrimental impact on our financial results and can result in the potential impairment of long-lived assets.

We may be disadvantaged competitively and financially by a significant movement of exploration and production operations to areas of the world in which we are not currently active.

The high cost or unavailability of infrastructure, materials, equipment, supplies and personnel 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. Rapid growth presents a challenge to us and our industry to recruit, train and retain our employees while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate. Labor-related actions, including strikes, slowdowns and facility occupations can also have a negative impact on our business.

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. In addition, we could incur additional taxes as a result of our resolution with the DOJ and SEC.

Our failure to comply with the terms of our agreements with the DOJ and SEC would have a negative impact on our ongoing operations.

Under the settlements with the DOJ and SEC, we are subject to a two-year deferred prosecution agreement and enjoined by the federal district court against any further violations of the FCPA. Accordingly, the settlements reached with the DOJ and SEC could be substantially nullified and we could be subject to severe sanctions and civil and criminal prosecution as well as fines and penalties in the event of a subsequent violation by us or any of our employees or our failure to meet all of the conditions contained in the settlements. The impact of the settlements on our ongoing operations could include limits on revenue growth and increases in operating costs. Our ability to comply with the terms of the settlements is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents and business partners and supervise, train and retain competent employees and the efforts of our employees to comply with applicable law and the Baker Hughes Business Code of Conduct.

Compliance with and changes in laws or adverse positions taken by taxing authorities could be costly and could affect operating results.

Our operations in the U.S. and over 90 countries can be impacted by expected and unexpected changes in the legal and business environments in which we operate. 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 regulation, new policies, investigations and legal proceedings and new interpretations of the existing legal rules and regulations, in particular, changes in export control laws or exchange control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in countries 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. Changes in our environmental liability could originate with the discovery of new environmental remediation sites, changes in environmental regulations, or the discharge of hazardous materials into the environment.

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 its contractors to meet local content requirements or other local standards that could be difficult 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.

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 require the Company to assume additional risks.

Changes in economic conditions and currency fluctuations may adversely affect our operating results.

Fluctuations in foreign currencies relative to the U.S. Dollar can impact our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars or local currency indexed to U.S. Dollars. Local expenses and some of our manufacturing costs are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign currencies, particularly the British Pound Sterling, Euro, Canadian Dollar, Norwegian Krone, Venezuelan Bolivar, Australian Dollar and Brazilian Real, can increase or decrease our expenses reported in U.S. Dollars and may adversely impact our results of operations.

The condition of the capital markets and equity markets in general can affect the price of our common stock and our ability to obtain financing, if necessary. If the Company’s credit rating is downgraded, this would increase our costs under our $500.0 million revolving credit agreement and commercial paper program, as well as the cost of obtaining, or make it more difficult to obtain or issue, new debt financing.

Our ability to forecast the size of and changes in the worldwide oil and natural gas industry and our ability to forecast our customers’ activity levels and demand for our products and services impacts our management of our manufacturing and distribution activities, our staffing levels and our cash and financing requirements. Unanticipated changes in our customers’ requirements can impact our costs, creating temporary shortages or surpluses of equipment and people and demands for cash or financing.

Changes in market conditions may impact any stock repurchases.

To the extent the Company engages in stock repurchases, such activity is subject to market conditions, such as the trading prices for our stock, as well as the terms of any stock purchase plans intended to comply with Rule 10b5-1 or Rule 10b-18 of the Exchange Act. Management in its discretion may engage in or discontinue stock repurchases at any time.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We are headquartered in Houston, Texas and operate 47 principal manufacturing plants, ranging in size from approximately 5,000 to 300,000 square feet of manufacturing space. The total aggregate area of the plants is approximately 3.3 million square feet, of which approximately 2.1 million square feet (64.9%) are located in the United States, 0.4 million square feet (10.5%) are located in Canada and South America, 0.8 million square feet (22.8%) are located in Europe, and a minimal amount of space is located in the Far East. Our principal manufacturing plants are located in: United States – Houston, Texas; Broken Arrow, Claremore and Tulsa, Oklahoma; Lafayette, Louisiana; Canada and South America – Calgary, Canada; Maracaibo, Venezuela; Mendoza, Argentina and Europe – Aberdeen and East Kilbride, Scotland; Celle, Germany; Belfast, Northern Ireland.

We own or lease numerous service centers, shops and sales and administrative offices throughout the geographic areas in which we operate. We also have a significant investment in service vehicles, rental tools and manufacturing and other equipment. We believe that our manufacturing facilities are well maintained and suitable for their intended purposes. The table below shows our principal manufacturing plants by segment and geographic area:


		Canada
		and
	United	South
Segment	States	America	Europe	Far East	Total

Completion and Production	16	4	7	1	28

Drilling and Evaluation	13	1	4	1	19

ITEM 3. LEGAL PROCEEDINGS

We are involved in litigation or proceedings that have arisen in our ordinary business activities. We insure against these risks to the extent deemed prudent by our management and to the extent insurance is available, but no assurance can be given that the nature and amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending and future legal proceedings. Many of these insurance policies contain deductibles or self-insured retentions in amounts we deem prudent and for which we are responsible for payment. In determining the amount of self-insurance, it is our policy to self-insure those losses that are predictable, measurable and recurring in nature, such as claims for automobile liability, general liability and workers compensation. We record accruals for the uninsured portion of losses related to these types of claims. The accruals for losses are calculated by estimating losses for claims using historical claim data, specific loss development factors and other information as necessary.

On September 12, 2001, we, without admitting or denying the factual allegations contained in the Order, consented with the SEC to the entry of an Order making Findings and Imposing a Cease-and-Desist Order (the “Order”) for violations of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Exchange Act. Among the findings included in the Order were the following: In 1999, we discovered that certain of our officers had authorized an improper $75,000 payment to an Indonesian tax official, after which we embarked on a corrective course of conduct, including voluntarily and promptly disclosing the misconduct to the SEC and the DOJ. In the course of our investigation of the Indonesia matter, we learned that we had made payments in the amount of $15,000 and $10,000 in India and Brazil, respectively, to our agents, without taking adequate steps to ensure that none of the payments would be passed on to foreign government officials. The Order found that the foregoing payments violated Section 13(b)(2)(A). The Order also found us in violation of Section 13(b)(2)(B) because we did not have a system of internal controls to determine if payments violated the FCPA. The FCPA makes it unlawful for U.S. issuers, including us, or anyone acting on their behalf, to make improper payments to any foreign official in order to obtain or retain business. In addition, as discussed below, the FCPA establishes accounting and internal control requirements for U.S. issuers. We cooperated with the SEC’s investigation.

By the Order, dated September 12, 2001 (previously disclosed by us and incorporated by reference in this annual report as Exhibit 99.1), we agreed to cease and desist from committing or causing any violation and any future violation of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Exchange Act. Such Sections of the Exchange Act require issuers to: (x) make and keep books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and maintain a system of internal accounting controls sufficient to provide reasonable assurances that: (i) transactions are executed in accordance with 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.

On March 29, 2002, we announced that we had been advised that the SEC and the DOJ were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the FCPA regarding anti-bribery, books and records and internal controls. In connection with the investigations, the SEC has issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We provided documents to and cooperated fully with the SEC and DOJ. In addition, we conducted internal investigations into these matters. Our internal investigations identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Angola, Kazakhstan and Nigeria, as well as potential liabilities to government authorities in Nigeria. Evidence obtained during the course of the investigations was provided to the SEC and DOJ.

On April 26, 2007, the United States District Court, Southern District of Texas, Houston Division (the “Court”) unsealed a three-count criminal information that had been filed against us as part of the execution of a Deferred Prosecution Agreement (the “DPA”) between us and the DOJ. The three counts arise out of payments made to an agent in connection with a project in Kazakhstan and include conspiracy to violate the FCPA, a substantive violation of the antibribery provisions of the FCPA, and a violation of the FCPA’s books-and-records provisions. All three counts relate to our operations in Kazakhstan during the period from 2000 to 2003. Although we did not plead guilty to that information, we face prosecution under that information, and possibly under other charges as well, if we fail to comply with the terms of the DPA. Those terms include, for the two-year term of the DPA, full cooperation with the government; compliance with all federal criminal law, including but not limited to the FCPA; and adoption of a Compliance Code containing specific provisions intended to prevent violations of the FCPA. The DPA also requires us to retain an independent monitor for a term of three years to assess and make recommendations about our compliance policies and procedures and our implementation of those procedures. Provided that we comply with the DPA, the DOJ has agreed not to prosecute us for violations of the FCPA based on information that we have disclosed to the DOJ regarding our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, Uzbekistan, Turkmenistan, and Azerbaijan, among other countries.

On the same date, the Court also accepted a plea of guilty by our subsidiary Baker Hughes Services International, Inc. (“BHSII”) pursuant to a plea agreement between BHSII and the DOJ (the “Plea Agreement”) based on similar charges relating to the same conduct. Pursuant to the Plea Agreement, BHSII agreed to a three-year term of organizational probation. The Plea Agreement contains provisions requiring BHSII to cooperate with the government, to comply with all federal criminal law, and to adopt a Compliance Code similar to the one that the DPA requires of the Company.

Also on April 26, 2007, the SEC filed a Complaint (the “SEC Complaint”) and a proposed order (the “SEC Order”) against us in the Court. The SEC Complaint and the SEC Order were filed as part of a settled civil enforcement action by the SEC, to resolve the civil portion of the 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 SEC Order. The SEC Complaint alleges 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 SEC’s cease and desist order of September 12, 2001. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order enjoins us from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that we retain the independent monitor to assess our FCPA compliance policies and procedures for the three-year period.

Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid, in the second quarter of 2007, $44.1 million ($11 million in criminal penalties, $10 million in civil penalties, $19.9 million in disgorgement of profits and $3.2 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement. We previously disclosed copies of these agreements and settlements and the same are incorporated by reference in this annual report as Exhibits 10.54, 10.55 and 99.2 through 99.7

We have retained, and the SEC and DOJ have approved, an independent monitor to assess our FCPA compliance policies and procedures for the specified three-year period.

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. The lawsuits brought by the Sheetmetal Workers’ National Pension Fund and The Alaska Plumbing and Pipefitting Industry Pension Trust are pending in the Houston Division of the United States District Court for the Southern District of Texas. These lawsuits have been consolidated and an amended complaint in the consolidated action was filed on October 15, 2007. The lawsuit brought by Chris Larson is pending in the 215th District Court of Harris County, Texas. We do not expect these lawsuits to have a material adverse effect on our consolidated financial statements.

On May 12, 2006, Baker Hughes Oilfield Operations, Inc. (“BHOO”), a subsidiary of the Company, was named as a defendant in a lawsuit in the United States District Court, Eastern District of Texas brought by Reed Hycalog against BHOO and other third parties arising out of alleged patent infringement relating to the sale of certain diamond drill bits utilizing certain types of polycrystalline diamond cutters sold by our Hughes Christensen division. Reed Hycalog seeks compensatory damages and injunctive relief against the defendants, as well as attorneys’ fees and other costs. On September 11, 2007, the court issued a ruling regarding the scope of Reed Hycalog’s patent infringement claims. On January 18, 2008, Reed Hycalog filed with the court a report claiming an amount of compensatory damages due from Baker Hughes ranging from approximately $51 million to approximately $226 million. Reed Hycalog has also claimed they are entitled to enhanced damages and attorney fees. The Company and BHOO believe they have reasonable defenses to these claims and have asserted counter-claims for infringement by Reed Hycalog of certain of our drill bit patents in the lawsuit. We are not able to predict the outcome of this litigation or its impact on our consolidated financial statements.

Further information is contained in the “Environmental Matters” section of Item 1 herein.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET FOR 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, 2008, there were approximately 295,000 stockholders and approximately 15,800 stockholders of record.

For information regarding quarterly high and low sales prices on the New York Stock Exchange for our common stock during the two years ended December 31, 2007, and information regarding dividends declared on our common stock during the two years ended December 31, 2007, see Note 17 of the Notes to Consolidated Financial Statements in Item 8 herein.

The following table contains information about our purchases of equity securities during the fourth quarter of 2007.

Issuer Purchases of Equity Securities


					Total						Maximum
					Number of						Number (or
					Shares				Total		Approximate
					Purchased				Number of		Dollar Value) of
					as Part of a				Shares		Shares that May
	Total Number		Average		Publicly		Average		Purchased		Yet Be
	of Shares		Price Paid		Announced		Price Paid		in the		Purchased Under
Period	Purchased⁽¹⁾		Per Share⁽¹⁾		Program⁽²⁾		Per Share⁽³⁾		Aggregate		the Program⁽⁴⁾

October 1-31, 2007		13,336	$	91.56		1,200	$	85.01		14,536	$	—
November 1-30, 2007		—		—		1,551,300		81.36		1,551,300		—
December 1-31, 2007		—		—		1,401,546		82.18		1,401,546		—

Total		13,336	$	91.56		2,954,046	$	81.75		2,967,382	$	823,958,000


⁽¹⁾		Represents shares purchased from employees to pay the option exercise price related to stock-for-stock exchanges in option exercises or to satisfy the tax withholding obligations in connection with the vesting of restricted stock awards and restricted stock units.

⁽²⁾		Repurchases were made under Stock Purchase Plans with an agent that complied with the requirements of Rule 10b5-1 of the Exchange Act (the “Plans”) as well as open market purchases that complied with Rule 10b-18 of the Exchange Act. On August 31, 2007, we entered into a Plan that ran from September 4, 2007 through October 31, 2007. On December 7, 2007, we entered into a Plan that ran from December 10, 2007 through February 20, 2008. Under the Plans, the agent repurchased a number of shares of our common stock determined under the terms of the Plan each trading day based on the trading price of the stock on that day. Shares were repurchased under the Plans by the agent at the prevailing market prices, in open market transactions which complied with Rule 10b-18 of the Exchange Act.

⁽³⁾		Average price paid includes commissions.

⁽⁴⁾		In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock which was in addition to the balance remaining from the Board of Directors’ previous authorization. On July 26, 2007, our Board of Directors authorized a plan to repurchase up to $1.0 billion of our common stock, from time to time, in addition to the existing stock repurchase plan. During the fourth quarter of 2007, we repurchased 3.0 million shares of our common stock at an average price of $81.75 per share, for a total of $241.5 million with authorization remaining to repurchase up to a total of $824.0 million of our common stock as of the end of 2007. Stock repurchases in 2008 (through February 19, 2008) were 8.0 million shares of common stock at an average price of $68.95 per share for a total of $551.8 million. As of February 19, 2008, we have authorization remaining to repurchase up to a total of $272.2 million of our common stock.

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 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 Oil and Gas Equipment and Services Index


	2002		2003		2004		2005		2006		2007

Baker Hughes	$	100.00	$	101.47	$	136.25	$	195.93	$	242.32	$	264.98
S&P 500 Index		100.00		128.68		142.68		149.69		173.33		182.85
S&P Oil and Gas Equipment and Services Index		100.00		124.74		164.48		244.37		282.34		417.57



*		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, 2002 in Baker Hughes common stock, the S&P 500 Index and the S&P Oil and Gas Equipment and Services Index.

The Corporate Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that Baker Hughes specifically incorporates it by reference into such filing.

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)	2007			2006			2005			2004			2003

Revenues	$	10,428.2		$	9,027.4		$	7,185.5		$	6,079.6		$	5,233.3
Costs and expenses:
Cost of revenues		6,845.6			5,876.4			5,023.7			4,428.3			3,867.2
Research and engineering		372.0			338.9			299.6			271.7			253.9
Marketing, general and administrative		932.8			877.8			628.8			563.2			511.0
Impairment of investment in affiliate		—			—			—			—			45.3
Restructuring charge reversals		—			—			—			—			(1.1	)

Total costs and expenses		8,150.4			7,093.1			5,952.1			5,263.2			4,676.3

Operating income		2,277.8			1,934.3			1,233.4			816.4			557.0
Equity in income (loss) of affiliates		1.2			60.4			100.1			36.3			(137.8	)
Gain on sale of interest in affiliate		—			1,743.5			—			—			—
Interest expense		(66.1	)		(68.9	)		(72.3	)		(83.6	)		(103.1	)
Interest and dividend income		43.8			67.5			18.0			6.8			5.3

Income from continuing operations before income taxes		2,256.7			3,736.8			1,279.2			775.9			321.4
Income taxes		(742.8	)		(1,338.2	)		(404.8	)		(250.6	)		(145.6	)

Income from continuing operations		1,513.9			2,398.6			874.4			525.3			175.8
Income (loss) from discontinued operations, net of tax		—			20.4			4.9			3.3			(41.3	)

Income before cumulative effect of accounting change		1,513.9			2,419.0			879.3			528.6			134.5
Cumulative effect of accounting change, net of tax		—			—			(0.9	)		—			(5.6	)

Net income	$	1,513.9		$	2,419.0		$	878.4		$	528.6		$	128.9


Per share of common stock:
Income from continuing operations:
Basic	$	4.76	$	7.26	$	2.58	$	1.57	$	0.52
Diluted		4.73		7.21		2.56		1.57		0.52
Dividends		0.52		0.52		0.475		0.46		0.46

Balance Sheet Data:
Cash, cash equivalents and short-term investments	$	1,054.4	$	1,103.7	$	774.0	$	319.0	$	98.4
Working capital		3,837.7		3,345.9		2,479.4		1,738.3		1,210.5
Total assets		9,856.6		8,705.7		7,807.4		6,821.3		6,416.5
Long-term debt		1,069.4		1,073.8		1,078.0		1,086.3		1,133.0
Stockholders’ equity		6,305.6		5,242.9		4,697.8		3,895.4		3,350.4

NOTES TO SELECTED FINANCIAL DATA


(1)		Discontinued operations. The selected financial data includes reclassifications to reflect Baker Supply Products Division, Baker Hughes Mining Tools, BIRD Machine, EIMCO Process Equipment and our oil producing operations in West Africa as discontinued operations. See Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding discontinued operations.

(2)		Reclassifications.During the fourth quarter of 2007, we began classifying certain expenses as cost of sales and cost of services and rentals that were previously classified as selling, general and administrative expenses. The change was the result of an internal review to improve management reporting. The reclassified expenses relate to selling and field service costs which are closely related to operating activities. In addition, we have renamed selling, general and administrative expenses on the statement of operations to marketing, general and administrative expenses to more accurately describe the costs included therein. The impact of these reclassifications is to increase cost of sales by $366.1 million, $318.6 million, $276.2 million, $266.4 million and $177.8 million for the years ended December 31, 2007, 2006, 2005, 2004 and 2003, respectively; increase cost of services and rentals by $123.9 million, $114.3 million, $104.7 million, $82.6 million and $135.7 million for the years ended


		December 31, 2007, 2006, 2005, 2004 and 2003, respectively; and decrease marketing, general and administrative expense by $490.0 million, $432.9 million, $380.9 million, $349.0 million and $313.5 million for the years ended December 31, 2007, 2006, 2005, 2004 and 2003, respectively. These reclassifications had no impact on total costs and expenses as these changes offset one another. All prior periods have been reclassified to conform to this new presentation.

(3)		Equity in income (loss) of affiliates and impairment of investment in affiliate. In 2003, we recorded $135.7 million in equity in income (loss) of affiliates for our share of $452.0 million of certain impairment and restructuring charges taken by WesternGeco, a seismic venture in which we had a 30% interest. The charges related to the impairment of WesternGeco’s multiclient seismic library and rationalization of WesternGeco’s marine seismic fleet. In addition, as a result of the continued weakness in the seismic industry, we evaluated the value of our investment in WesternGeco and recorded an impairment loss of $45.3 million in 2003 to write-down the investment to its fair value. In April 2006, we sold our 30% interest in WesternGeco.

(4)		Restructuring charge reversals. In 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and recorded a restructuring charge of $29.5 million. Included in the restructuring charge was $1.1 million for a contractual obligation related to an oil and natural gas property in Angola. The property was sold in 2003, and we reversed the liability related to this contractual obligation.

(5)		Gain on sale of interest in affiliate. On April 28, 2006, we sold our 30% interest in WesternGeco, a seismic venture we formed with Schlumberger in 2000, to Schlumberger for $2.4 billion. We recorded a pre-tax gain of $1,743.5 million on the sale. See Note 5 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding this sale.

(6)		Cumulative effect of accounting change. In 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations. In 2003, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations.

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 leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We report our results under two segments – Drilling and Evaluation and Completion and Production – 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 divisions during business cycles. Collectively, we refer to the results of these two segments as Oilfield Operations.

	•		The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline formation evaluation and wireline completion services) divisions. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells.

	•		The Completion and Production segment consists of the Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electrical submersible pumps and progressing cavity pumps) divisions. The Completion and Production segment also includes our ProductionQuest (production optimization and permanent monitoring) business unit. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

We previously reported a third segment, WesternGeco, which consisted of our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger. On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion and recorded a pre-tax gain of $1,743.5 million ($1,035.2 million after-tax).

We operate in over 90 countries around the world and our corporate headquarters is in Houston, Texas. We have significant manufacturing operations in various countries, including, but not limited to, the United States (Texas, Oklahoma and Louisiana), the United Kingdom (Scotland and Northern Ireland), Germany (Celle), and South America (Venezuela and Argentina). As of December 31, 2007, we had approximately 35,800 employees, up 1,200 employees from December 31, 2006. Approximately 57% of our employees work outside the United States.

2007 Financial Results

We reported revenues of $10,428.2 million for 2007, a 15.5% increase compared with 2006, exceeding the 2.3% increase in the worldwide average rig count for 2007 compared with 2006. During 2007, the rig count continued to increase outside North America, as oil and natural gas companies around the world recognized the need to build productive capacity to meet the growing demand for hydrocarbons and to offset depletion of existing developed reserves. The North American rig count was flat in 2007 compared to 2006 primarily due to the weak market conditions in Canada and offshore U.S., which offset growth in the U.S. land market. Oil prices were at historic highs in 2007, reflecting continued strong demand and relatively low spare productive capacity as well as a weaker U.S. Dollar. In addition to the growth in our revenues from increased activity, our revenues were impacted by changes in market share in certain product lines and to a lesser extent pricing improvements. Net income for 2007 was $1,513.9 million, compared with $2,419.0 million in 2006, which included $1,035.2 million after-tax gain on the sale of our interest in WesternGeco.

Below are details of the Oilfield Operations revenue by region (dollar amounts in millions).


Revenue by Region
							Europe, Africa,
	North			Latin			Russia and the			Middle East,			Oilfield
Year Ended	America⁽¹⁾			America⁽²⁾			Caspian⁽³⁾			Asia Pacific⁽⁴⁾			Operations

December 31, 2007	$	4,358.0		$	990.1		$	3,065.6		$	2,014.5		$	10,428.2
December 31, 2006		3,999.6			826.7			2,472.6			1,728.5			9,027.4

$ Increase	$	358.4		$	163.4		$	593.0		$	286.0		$	1,400.8
% Increase		8.9	%		19.7	%		24.0	%		16.5	%		15.5	%


⁽¹⁾		United States and Canada.

⁽²⁾		Mexico, Central America and South America.

⁽³⁾		Europe, Africa, Russia and the Caspian area, excluding Egypt.

⁽⁴⁾		Middle East and Asia Pacific, including Egypt.

	•		The 8.9% increase in North America revenue was driven by a strong increase in gas-directed horizontal drilling on land in the U.S. where the rig count for land and inland water drilling increased 8.7% in 2007 compared with 2006. Revenue from the U.S. offshore market was impacted by the ongoing migration of rigs out of the Gulf of Mexico to more attractive international markets and weather-related disruptions. U.S. offshore revenue was up 2.9% compared to a rig count that was down 18.9% in 2007 compared with 2006. Revenue from Canada was down reflecting lower economic returns for Canadian exploration and production projects evidenced by a rig count that declined 27.2% compared to 2006.

	•		Outside of North America revenue increased 20.7% in 2007 compared with 2006.

	•		Latin America revenue increased 19.7% in 2007 compared with 2006, while the Latin America rig count was up 9.6%. The increase was driven by market share gains in Brazil and drilling activity increases in Colombia.

	•		A 24.0% increase in Europe, Africa, Russia and the Caspian revenue was driven by an increase in revenue from Russia and the Caspian of 50.4%, revenue from projects in Equatorial Guinea and revenue from projects in the U.K. and the Norwegian sector of the North Sea. Revenue in Europe increased 19.6% while the rig count was flat compared with 2006. Revenue in Africa increased 17.0% exceeding rig count increases of 13.8% compared with 2006. We do not count rigs in Russia or the Caspian.

	•		Middle East and Asia Pacific revenues were up 16.5% in 2007 compared with 2006. Revenue from the Middle East was up 18.1%, driven by our activities in Saudi Arabia and Qatar, compared to the Middle East rig count which increased 11.3%. Asia Pacific revenue was up 15.0%, driven by our activities in Australia, Malaysia and India, compared to the Asia Pacific rig count that increased 5.7%. We do not count rigs for onshore China.

The customers for our products and services include the super-major and major integrated oil and natural gas companies, independent oil and natural gas companies and state-owned national oil companies (“NOCs”). Our ability to compete in the oilfield services market is dependent on our ability to differentiate our product and service offerings by technology, service and the price paid for the value we deliver.

The primary driver of our business is our customers’ capital and operating expenditures dedicated to exploring, and drilling for, and developing and producing oil and natural gas. Our business is cyclical and is dependent upon our customers’ forecasts of future oil and natural gas prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas production. During 2007, our customers’ spending directed to both worldwide oil and North American natural gas projects increased compared with 2006. The increase in spending was driven by the multi-year requirement to find, develop and produce more hydrocarbons to meet the growth in demand, offset production declines, increase inventory levels and increase spare productive capacity. Additionally, the increase was supported by historically high oil and natural gas prices.

BUSINESS ENVIRONMENT

Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration, development, and production of oil and natural gas reserves. Spending by oil and natural gas exploration and production companies is dependent upon their forecasts regarding the expected future supply and future demand for oil and natural gas products and their estimates of risk-adjusted costs to find, develop, and produce reserves. Changes in oil and natural gas

exploration and production spending will normally result in increased or decreased demand for our products and services, which will be reflected in the rig count and other measures.

Oil and Natural Gas Prices

Generally, changes in the current price and expected future price of oil or natural gas drive customers’ expectations about their prospects from oil and natural gas sales and their expenditures to explore for or produce oil and natural gas. Accordingly, changes in these expenditures will normally result in increased or decreased demand for our products and services. Oil (Bloomberg West Texas Intermediate (WTI) Cushing Crude Oil Spot Price) and natural gas (Bloomberg Henry Hub Natural Gas Spot Price) prices are summarized in the table below as averages of the daily closing prices during each of the periods indicated.


	2007		2006		2005

Oil prices ($/Bbl)	$	72.23	$	66.09	$	56.59
Natural gas prices ($/mmBtu) *		6.96		6.73		8.66


*		In late September 2005, Hurricane Rita damaged natural gas processing facilities in Henry, Louisiana (“Henry Hub”) and the New York Mercantile Exchange declared force majeure on its Henry Hub natural gas contracts. As a result, the average natural gas prices for 2005 exclude price data for September 22, 2005 through October 6, 2005 when there was insufficient activity to determine a spot price.

Oil prices averaged a nominal historic high of $72.23/Bbl for the year 2007. The year 2007 began with oil prices declining to a yearly low of $50.48/Bbl in mid-January. Throughout the balance of the year oil prices continued to increase due to concerns about weak inventory levels, limited worldwide excess productive capacity and concerns that demand growth would outpace production growth. The weakening of the U.S. Dollar relative to other currencies also contributed to the higher price. Oil prices reached a yearly high of $98.88/Bbl in mid-November 2007.

Natural gas prices averaged $6.96/mmBtu for the year 2007. The year 2007 began with record levels of natural gas in storage and gas prices in the low $5/mmBtu range. However, cold weather from mid-January to early February resulted in higher than anticipated withdrawals of gas in storage and placed upward pressure on gas prices, which increased to a yearly high of $9.07/mmBtu in early February 2007. As natural gas inventory continued to build throughout the year, gas prices again came under pressure, hitting a low of $5.29/mmBtu in early September. Prices recovered in late September on expectations of cooler weather and ended the year over $7/mmBtu.

Rig Counts

We have been providing rig counts to the public since 1944. We gather all relevant data through our field service personnel, who obtain the necessary data from routine visits to the various rigs, customers, contractors or other outside sources. This data is then compiled and distributed to various wire services and trade associations and is published on our website. Rig counts are compiled weekly for the U.S. and Canada and monthly for all international and U.S. workover rigs. Published international rig counts do not include rigs drilling in certain locations, such as Russia, the Caspian and onshore China, because this information cannot be readily obtained.

Rigs in the U.S. are counted as active if, on the day the count is taken, the well being drilled has been started but drilling has not been completed and the well is anticipated to be of sufficient depth, which may change from time to time and may vary from region to region, to be a potential consumer of our drill bits. Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, a weekly or daily average of active rigs is taken. In those international areas where there is poor availability of data, the rig counts are estimated from third party data. The rig count does not include rigs that are in transit from one location to another, are rigging up, are being used in non-drilling activities, including production testing, completion and workover, or are not significant consumers of drill bits.

Our rig counts are summarized in the table below as averages for each of the periods indicated.


	2007		2006		2005⁽¹⁾

U.S. – land and inland waters		1,695		1,559		1,290
U.S. – offshore		73		90		93
Canada		343		471		455

North America		2,111		2,120		1,838

Latin America		355		324		316
North Sea		48		49		43
Other Europe		29		28		27
Africa		66		58		50
Middle East		265		238		190
Asia Pacific		241		228		225

Outside North America		1,004		925		851

Worldwide		3,115		3,045		2,689


⁽¹⁾		Restated to exclude rig counts for Iran and Sudan, which counts were discontinued as of December 31, 2005.

The U.S. land and inland waters rig count increased 8.7% in 2007 compared with 2006, due to increased natural gas drilling activity. The U.S. offshore rig count decreased 18.9% in 2007 compared with 2006, reflecting the ongoing migration of rigs out of the Gulf of Mexico to more attractive markets and weather-related disruptions. The Canadian rig count decreased 27.2% over 2006 levels due to lower activity resulting from less-favorable economics for natural gas producers.

Outside North America, the rig count increased 8.5% in 2007 compared with 2006. The rig count in Latin America increased 9.6% in 2007 compared with 2006, driven primarily by activity increases in Colombia, Brazil and Mexico. The North Sea rig count was down slightly in 2007 compared with 2006. The rig count in Africa increased by 13.8% in 2007 compared with 2006. Activity in 2007 in the Middle East increased 11.3% compared with 2006, driven primarily by activity increases in Saudi Arabia, Egypt and Oman. The rig count in the Asia Pacific region was up 5.7% in 2007 compared with 2006, with modest increases in multiple countries across the region.

RESULTS OF OPERATIONS

The discussions below relating to significant line items from our consolidated statements of operations are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items. The discussions are based on our consolidated financial results, as individual segments do not contribute disproportionately to our revenues, profitability or cash requirements. In addition, the discussions below for revenues and cost of revenues are on a combined basis as the business drivers for the individual components of product sales and service and rentals are similar.

During the fourth quarter of 2007, we began classifying certain expenses as cost of sales and cost of services and rentals that were previously classified as selling, general and administrative expenses. The change was the result of an internal review to improve management reporting. The reclassified expenses relate to selling and field service costs which are closely related to operating activities. In addition, we have renamed selling, general and administrative expenses on the statement of operations to marketing, general and administrative expenses to more accurately describe the costs included therein. The impact of these reclassifications is to increase cost of sales by $366.1 million, $318.6 million and $276.2 million for the years ended December 31, 2007, 2006 and 2005, respectively; increase cost of services and rentals by $123.9 million, $114.3 million and $104.7 million for the years ended December 31, 2007, 2006 and 2005, respectively; and decrease marketing, general and administrative expense by $490.0 million, $432.9 million and $380.9 million for the years ended December 31, 2007, 2006 and 2005, respectively. These reclassifications had no impact on total costs and expenses as these changes offset one another. All prior periods have been reclassified to conform to this new presentation.

The table below details certain consolidated statement of operations data and their percentage of revenues for 2007, 2006 and 2005 (dollar amounts in millions).


	2007					2006					2005
	$		%			$		%			$		%

Revenues	$	10,428.2		100.0	%	$	9,027.4		100.0	%	$	7,185.5		100.0	%
Cost of revenues		6,845.6		65.6	%		5,876.4		65.1	%		5,023.7		69.9	%
Research and engineering		372.0		3.6	%		338.9		3.8	%		299.6		4.2	%
Marketing, general and administrative		932.8		8.9	%		877.8		9.7	%		628.8		8.8	%

Revenues

Revenues for 2007 increased 15.5% compared with 2006, primarily due to increases in activity in certain geographic areas and, to a lesser extent, improvement in price. Revenues in North America, which accounted for 41.8% of total revenues, increased 9.0% in 2007 compared with 2006. Revenues from our U.S. land operations increased 15.4% compared to a rig count that increased 8.7%, which reflects a continued increase in gas-directed horizontal drilling. Revenue from the U.S. offshore market increased 2.9% compared to a rig count that decreased 18.9%. These increases more than offset an 8.6% decline in Canadian revenue where the rig count declined 27.2%. Revenues outside North America, which accounted for 58.2% of total revenues, increased 20.7% in 2007 compared with 2006. This increase reflects the improvement in international drilling activity, as evidenced by the 8.5% increase in the rig count outside North America, particularly in Latin America, Africa, the Middle East and Asia Pacific region, coupled with improvements in certain markets and product lines and price increases.

Revenues for 2006 increased 25.6% compared with 2005, primarily due to increases in activity, as evidenced by a 13.2% increase in the worldwide rig count, pricing improvements of between seven and nine percent and increases in market share in selected product lines and geographic areas. Revenues in North America, which accounted for 44.3% of total revenues, increased 31.2% for 2006 compared with 2005. This increase reflects a continued broad based increase in drilling activity in the U.S., as evidenced by the 15.3% increase in the North American rig count, with activity dominated by land-based gas-directed drilling. Revenues outside North America, which accounted for 55.7% of total revenues, increased 21.5% for 2006 compared with 2005. This increase reflects the improvement in international drilling activity in 2006, as evidenced by the 8.7% increase in the rig count outside North America, particularly in the Middle East, Africa and the North Sea, coupled with price increases in certain markets and product lines.

Cost of Revenues

Cost of revenues for 2007 increased 16.5% compared with 2006. Cost of revenues as a percentage of revenues was 65.6% and 65.1% for 2007 and 2006, respectively. The increase in cost of revenues as a percentage of consolidated revenues was primarily due to a change in the geographic and product mix from the sale of our products and services and increasing competitive conditions and pricing pressures, particularly in North America. In addition higher raw material costs and employee compensation costs contributed to the increase. Effective January 1, 2007, we increased the depreciable lives of certain assets of our Baker Atlas division resulting in a reduction to cost of services and rentals for 2007 of approximately $23 million.

Cost of revenues for 2006 increased 17.0% compared with 2005. Cost of revenues as a percentage of revenues was 65.1% and 69.9% for 2006 and 2005, respectively. The decrease in cost of revenues as a percentage of consolidated revenues was primarily the result of overall average price increases between seven and nine percent and continued high utilization of our rental tool fleet and personnel. A change in the geographic and product mix from the sale of our products and services also contributed to the decrease in the cost of revenues as a percentage of revenues. This increase was partially offset by higher raw material costs and employee compensation costs. In addition to these factors, during the fourth quarter of 2006, we revised the accounting procedures related to certain inventory for our Baker Atlas division resulting in a one time reduction in cost of services and rentals in 2006 of $21.2 million.

Research and Engineering

Research and engineering expenses increased 9.8% in 2007 compared with 2006 and 13.1% in 2006 compared with 2005. The increase in both years reflects our commitment in developing and commercializing new technologies as well as investing in our core product offerings. 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 is scheduled for completion in 2008.

Marketing, General and Administrative

Marketing, general and administrative expenses increased 6.3% in 2007 compared with 2006. The 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.

Marketing, general and administrative expenses increased 39.6% in 2006 compared with 2005. The increase corresponds with increased activity and resulted primarily from higher marketing and employee compensation costs, including stock-based compensation which increased due to the adoption of Statement of Financial Accounting Standard No. 123(R) –Shared Based Payment, using the modified prospective application method. The increase also results from the financial charge of $46.1 million recorded in the fourth quarter of 2006 in connection with the settlement negotiations with the SEC and DOJ.

Equity in Income of Affiliates

Equity in income of affiliates decreased $59.2 million in 2007 compared with 2006 and $39.7 million in 2006 compared with 2005. These decreases in equity in income of affiliates are due to the sale of our 30% interest in WesternGeco on April 28, 2006.

Gain on Sale of Interest in Affiliate

On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in cash and recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, after-tax).

Interest Expense and Interest and Dividend Income

Interest expense decreased $2.8 million in 2007 compared with 2006 and $3.4 million in 2006 compared with 2005. These decreases were primarily due to slightly lower average total debt levels. Interest and dividend income in 2007 decreased $23.7 million over 2006, primarily due to lower average cash and short-term investment balances in 2007 as a result of our share repurchase programs. Interest and dividend income in 2006 increased $49.5 million over 2005, primarily due to the interest and dividends earned on the invested cash received from the sale of our interest in WesternGeco.

Income Taxes

Our effective tax rate in 2007 is 32.9%, which is lower than the U.S. statutory income tax rate of 35% due to lower rates of tax on certain international operations offset by state income taxes. Our effective tax rate in 2006 was 35.8%, which was higher than the U.S. statutory income tax rate of 35% due to taxes related to the sale of our interest in the WesternGeco venture and state income taxes, offset by lower rates of tax on our international operations. During 2006, we provided $708.3 million for taxes related to the sale of our interest in WesternGeco, which included an estimate of taxes related to the future repatriation of the non-U.S. proceeds. In 2005 our effective tax rate was 31.6%, which reflected a $10.6 million reduction to tax expense attributable to the recognition of a deferred tax asset associated with our supplemental retirement plan.

Our tax filings for various periods are subject to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessment of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable. We provide for uncertain tax positions pursuant to FIN 48,Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.

Cumulative Effect of Accounting Change

On December 31, 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47,Conditional Asset Retirement Obligations(“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with the special handling of asbestos related materials in certain facilities.

OUTLOOK

Worldwide Oil and Natural Gas Industry Outlook

This section should be read in conjunction with the factors described in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 7, both contained herein. These factors could impact, either positively or negatively, our expectation for: oil and natural gas demand; oil and natural gas prices; exploration and development spending and drilling activity; and production spending.

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 energy price forecasts below are based on information provided by our customers as well as market research and analyst reports including theShort Term Energy Outlook(“STEO”) published by the Energy Information Administration of the U.S. Department of Energy (“DOE”), theOil Market Reportpublished by the International Energy Agency (“IEA”) and theMonthly Oil Market Reportpublished by the Organization for Petroleum Exporting Countries (“OPEC”). Our outlook for production spending is based primarily on energy price forecasts and forecasts of expected oil and natural gas production levels.

Our outlook for activity outside of North America is heavily influenced by our expectations for oil prices and our outlook for activity in North America is heavily influenced by our expectations for North American natural gas prices.

Expectations for Oil Prices- Demand for oil is expected to increase in a range from 1.3 to 2.0 million barrels per day in 2008 compared to 2007. Non-OPEC supply is expected to increase 0.6 to 1.1 million barrels per day. The gap between increased demand and non-OPEC supply is expected to be met with increased OPEC supply and decreases in oil inventories. Inventories and spare productive capacity, which buffer oil markets from supply disruptions, are expected to remain relatively low reflecting the continuing tight balance between supply and demand. In its January 2008 STEO, the DOE forecasted oil prices to average $87/Bbl in 2008 and given the relatively low levels of inventory and spare productive capacity, prices are expected to remain volatile. The DOE expects increased production capacity in 2009 to result in prices falling to $82/Bbl. Delays in either OPEC or non-OPEC supply additions could impact this forecast.

We believe that these forecasts are similar to the forecasts our customers are using to plan their current spending levels and, with prices averaging between $60/Bbl and $100/Bbl, our customers will continue to execute their capital budgets as planned. Our customers are more likely to reduce their capital budgets if the oil price were expected to trade below $60/Bbl for an extended period of time. The risks to oil prices falling significantly below $60/Bbl include: (1) a significant economic recession in either the U.S. and/or China; (2) increases in non-OPEC production; (3) any significant disruption to worldwide demand; (4) reduced geo-political tensions; (5) poor OPEC quota discipline; or (6) other factors that result in spare productive capacity and higher oil inventory levels or decreased demand. If prices were to rise significantly above $100/Bbl there is a risk that the high energy price environment could destroy demand and significantly slow economic growth. If economic growth were to slow, our customers would likely decrease their capital spending from current levels. The primary risk of oil prices exceeding $100/Bbl is a supply disruption in a major oil exporting country including Iran, Saudi Arabia, Iraq, Venezuela, Nigeria or Norway.

Expectations for North American Natural Gas Prices- In its January 2008 STEO, the DOE forecasted that U.S. natural gas demand would increase 0.6% in 2008 compared to 2007 assuming normal weather. The demand for U.S. natural gas will be met by production from fields in the U.S., pipeline imports from Canada, and imports of LNG with natural gas storage buffering demand and supply. At current U.S. drilling activity levels, additions of new supply are expected to offset production declines and U.S. supply is expected to increase 1.6% in 2008 compared to 2007. Canadian imports are expected to decrease as a result of lower activity levels in Canada and increased demand within Canada. LNG imports are dependent on global demand for LNG with the U.S. playing the role of the market of last resort, accepting gas into storage if it is not needed in other international markets. Capacity to accept LNG imports is not expected to constrain LNG imports. In its January 2008 STEO, the DOE forecasted that U.S. natural gas prices are expected to average approximately $8/mmBtu in 2008.

We believe that our customers’ forecasts are similar to the DOE’s. Prices are expected to remain volatile through 2008 with weather-driven demand, imports of Canadian gas, LNG imports and production from lower 48 gas fields playing significant roles in determining price volatility. Variations in the supply demand balance will be reflected in gas storage levels. Based on industry data regarding production decline rates, we believe that a significant reduction in drilling activity in the U.S. or Canada would result in decreased production within one or two quarters helping to rebalance supply and demand quickly.

Industry Activity and Customer Spending- Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices described above, our outlook for drilling activity, as measured by the Baker Hughes rig count and anticipated customer spending trends are as follows:

	•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase approximately 15% to 20% in 2008 compared with 2007. Drilling activity outside of North America is expected to increase approximately 8% to 10% in 2008 compared with 2007. Our assumptions regarding overall growth in customer spending outside of North America assume stable economic growth in the U.S., China and the balance of the world outside of North America. Our expectations for spending could decrease if there are disruptions in key oil and natural gas production markets or significant weakening of the economies in the U.S., China or other significant consumers of oil and natural gas.

	•		North America – Customer spending in North America, primarily towards developing natural gas supplies, is expected to increase moderately in 2008 compared to 2007. Drilling activity is expected to increase 2% to 3% in the U.S. on land; decrease 8% to 10% offshore U.S.; and decrease 8% to 10% in Canada with customer spending trends in each market reflecting these drilling activity trends. Production-oriented spending is expected to increase 4% to 6% reflecting increases in oil and gas production. Our expectations for spending and revenue growth in North America assume normal winter and summer weather, stable economic growth in the U.S. and a modest increase in LNG imports.

Company Outlook

This section should be read in conjunction with the factors described in the “Risk Factors Related to Our Business,” “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward-Looking Statements” sections contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

Outside North America –In 2008, we expect revenues outside North America to increase in a percentage range from the low to mid-teens compared with 2007, continuing the multi-year trend of growth in customer spending. Spending on large projects by NOCs are expected to reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half and in particular, a sequential decline in the first quarter of 2008 compared to the fourth quarter of 2007 of approximately $100 million in revenue primarily from our Completion and Production segment. In addition, customer spending could be affected by weather-related reductions in the North Sea in the first and second quarters of 2008. In 2007, 2006 and 2005, revenues outside North America were 58.2%, 55.7% and 57.6% of total revenues, respectively.

North America –Revenue growth in 2008 from North America is expected to be no more than moderate. Revenue increases from our U.S. land operations in our Drilling and Evaluation segment and moderate but steady growth from our Completion and Production segment throughout North America are expected to be partially offset by decreases in revenue from our Drilling and Evaluation segment in Canada and the U.S. offshore. In 2007, 2006 and 2005, North American revenues were 41.8%, 44.3%, and 42.4% of total revenues, respectively.

Other factors that could have a significant positive impact on profitability include: increasing prices for our products and services; lower than expected raw material and labor costs; and/or higher than planned activity. Conversely, less than expected price increases or price deterioration, higher than expected raw material and labor costs and/or lower than expected activity would have a negative impact on profitability. Our ability to improve pricing is dependent on demand for our products and services and our competitors’ strategies of managing capacity. While the commercial introduction of new technology is an important factor in realizing pricing improvement, without capital discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized.

Our 2008 capital budget supports the continuation of the infrastructure expansion we began in late 2006 and early 2007. In 2007, we opened new or expanded facilities in many regions and/or countries including Latin America, the Middle East, and Russia. In addition, we opened the first phase of our Center for Technology and Innovation in Houston, a research and engineering facility to design advanced completion systems for high pressure, high temperature hostile environments. In early 2008, we opened our new campus in Dubai which includes our Middle East and Asia Pacific region headquarters, a regional operations center, and a training center which expands our Eastern Hemisphere training capabilities. Capital expenditures are expected to be approximately $1.3 billion for 2008, including approximately $250 million to $300 million that we expect to spend on infrastructure, primarily outside of North America.

The execution of our 2008 business plan and the ability to meet our 2008 financial objectives are dependent on a number of factors. Key factors include: the strength of the oilfield services market outside North America and our ability to realize price increases

commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; our ability to meet our growth objectives in areas where the lack of transparency in the market makes operating under the Deferred Prosecution Agreement more difficult; and the strength of the North American markets and our ability to protect pricing in markets in which demand for oilfield services and industry capacity are more closely balanced. Other factors include, but are not limited to, our ability to: recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; expand our business in areas that are growing rapidly with customers whose spending is expected to increase substantially (such as NOCs), and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian region and India); manage increasing raw material and component costs (especially steel alloys, copper, tungsten carbide, lead, nickel, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization and manage our spending in the North American market depending on the relative strength or weakness of this market.

Compliance

We do business in over 90 countries including approximately one-half of the 30 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index survey for 2007. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our FCPA policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation.

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 laws and regulations and our Business Code of Conduct.

OurBest-in-ClassGlobal 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 referred to within the Company as “C²” or “Completely Compliant.” The Completely Compliant theme is intended to establish the properTone-at-the-Topthroughout the Company. Employees are consistently reminded that they play a crucial role in ensuring that the Company always conducts its business ethically, legally and safely.

Our Chief Compliance Officer (“CCO”) oversees the development, administration and enforcement of our Business Code of Conduct, as well as legal compliance standards, policies, procedures and processes. The CCO reports directly to the General Counsel and the Chairman of the Audit/Ethics Committee of our Board of Directors. The CCO has ready access to all of the other senior officers of the Company. Our legal compliance group of over 30 employees includes our CCO, our Global Ethics & Compliance Director, four Regional Trade Directors, FCPA due diligence counsel, and specialized investigative counsel. The legal compliance group and our other company attorneys located throughout the world are available to answer questions regarding the Compliance Program and provide assistance to employees.

Highlights of our Compliance Program include:

	•		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, specialized training on FCPA compliance for virtually all operations managers (approximately 8,000 employees) and specially designed training for all finance personnel (approximately 2,000 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;

	•		Comprehensive internal policies over such areas as payments to non-U.S. commercial agents, charitable donations relating to non-U.S. operations; gift-giving and travel and entertainment to non-U.S. government officials. In addition, we have country-specific guidance for customs standards, export and re-export controls, economic sanctions and antiboycott;

	•		We have a compliance council that meets quarterly and is comprised of division compliance officers, key line managers from our divisions, and senior representatives of the Ethics & Compliance Group, Finance, Security, Human Resources, Health, Safety and Environmental, and Internal Audit. This compliance council is responsible for assisting the CCO with the strategic direction, ongoing development, coordination, and implementation of the Compliance Program;

	•		We use technology to monitor and report on compliance matters, including a web-based antiboycott reporting tool and a planned future use of a global trade management software tool;

	•		We have a whistleblower program designed to encourage reporting of any ethics or compliance matters without fear of retaliation including a worldwide Business Helpline operated by a third party and currently available toll-free in 150 languages;

	•		We have established a Blue Ribbon Panel comprised of well-known outside experts advising us in the areas of securities and compliance laws;

	•		We have significantly reduced the number of our non-U.S. commercial agents that we use to conduct our business. For the non-U.S. agents we continue to use, we employ extensive pre-retention FCPA due diligence requirements, as well as proactive post-retention oversight; this includes, among other things, the maintenance of comprehensive due diligence records, and the certification, periodic recertification, and training of all non-U.S. commercial agents, including written acknowledgement by these agents of all of our FCPA requirements and policies; and

	•		We conduct periodic internal audits that include onsite legal/accounting audits of all non-U.S. third party commercial agents, specific FCPA audit steps in all audits conducted by the internal audit function and FCPA risk assessments by the Corporate Ethics & Compliance Group in specified countries such as those which are rated high on Transparency International’s Corruption Perception Index.

LIQUIDITY AND CAPITAL RESOURCES

Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During 2007, cash flows from operations were the principal sources of funding. We anticipate that cash flows from operations will be sufficient to fund our liquidity needs in 2008. We may incur short-term debt to fund expenses, capital expenditures and additional stock repurchases in the U.S. until cash can be cost effectively transferred to the U.S. from offshore. 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. We also have a $500.0 million committed revolving credit facility that provides back-up liquidity in the event an unanticipated and significant demand on cash flows could not be funded by operations. To the extent we have outstanding commercial paper; however, our ability to borrow under the credit facility is reduced.

Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our Company. In 2007, we used cash for a variety of activities including working capital needs, payment of dividends, repurchase of common stock and capital expenditures.

Cash Flows

Cash flows provided (used) by continuing operations by type of activity were as follows for the years ended December 31 (in millions):


	2007			2006			2005

Operating activities	$	1,474.7		$	589.7		$	949.6
Investing activities		(620.2	)		1,376.2			(465.3	)
Financing activities		(592.0	)		(1,926.4	)		(108.1	)

Statements of cash flows for entities with international operations that are local currency functional exclude the effects of the changes in foreign currency exchange rates that occur during any given year, as these are noncash changes. As a result, changes reflected in certain accounts on the consolidated statements of cash flows may not reflect the changes in corresponding accounts on the consolidated balance sheets.

Operating Activities

Cash flows from operating activities of continuing operations provided $1,474.7 million for the year ended December 31, 2007 compared with $589.7 million for the year ended December 31, 2006. Cash flows from operating activities for 2007 and 2006 were

reduced by $125.3 million and $555.1 million, respectively, for income tax payments related to the gain on the sale of our interest in WesternGeco. Excluding these income tax payments, cash flows from operating activities for 2007 and 2006 were $1,600.0 million and $1,144.8 million, respectively, an increase of $455.2 million. This increase is primarily due to an increase of $198.4 million in income from continuing operations adjusted for noncash items coupled with a decrease of $131.4 million in net operating assets and liabilities which used less cash. Cash flows from operating activities, excluding the WesternGeco transaction in 2006, have been steadily increasing over the last three years and we expect this trend to continue in 2008.

The underlying drivers of the changes in operating assets and liabilities are as follows:

	•		An increase in accounts receivable used $287.3 million in cash in 2007 compared with using $316.4 million in cash in 2006. This increase in accounts receivable was primarily due to the increase in revenues offset partially by an increase in collections as reflected in a decrease in days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) of approximately one day.

	•		A build up in inventory in anticipation of and related to increased activity used $141.8 million in cash in 2007 compared with using $364.9 million in cash in 2006.

	•		A net decrease in accounts payable, accrued employee compensation and other accrued liabilities used $113.0 million in cash in 2007 compared with providing $173.2 million in cash in 2006. This was primarily due to higher employee bonus payments made in cash (for bonuses accrued in 2006 and paid in 2007) coupled with lower bonus accrual requirements for 2007 compared to 2006. The increase in cash used in 2007 was also impacted by the payment of $44.1 million related to the settlement of the investigations by the SEC and DOJ.

Our contributions to our defined benefit pension plans in 2007 were approximately $21.0 million compared to 2006 contributions of approximately $34.0 million, a decrease of approximately $13.0 million. This reduction in contributions is primarily due to lower minimum funding requirements in our non-U.S. plans.

Cash flows from operating activities of continuing operations provided $589.7 million for the year ended December 31, 2006 compared with $949.6 million for the year ended December 31, 2005. Cash flows from operating activities for 2006 were reduced by $555.1 million of income tax payments related to the gain on the sale of our interest in WesternGeco. Excluding these income tax payments, cash flows from operating activities for 2006 were $1,144.8 million, an increase of $195.2 million from the prior year. This increase is primarily due to an increase in income from continuing operations adjusted for noncash items partially offset by a change in net operating assets and liabilities that used cash flows.

The underlying drivers of the changes in operating assets and liabilities are as follows:

	•		An increase in accounts receivable used $316.4 million in cash in 2006 compared with using $329.4 million in cash in 2005. This was due to an increase in revenues partially offset by a decrease in the quarterly days sales outstanding (defined as the average number of days our net trade receivables are outstanding based on quarterly revenues) of approximately two days.

	•		A build up in inventory in anticipation of and related to increased activity used $364.9 million in cash in 2006 compared with using $108.7 million in cash in 2005.

	•		An increase in accounts payable, accrued employee compensation and other accrued liabilities provided $173.2 million in cash in 2006 compared with providing $214.7 million in cash in 2005. This was due primarily to increased activity and increased employee compensation accruals.

Investing Activities

Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools in place to generate revenues from operations. Expenditures for capital assets totaled $1,127.0 million, $922.2 million and $478.3 million for 2007, 2006 and 2005, 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. The increase in capital assets in 2007 is a result of increased demand for our products and services.

During 2007, we purchased $2,520.7 million of and received proceeds of $2,838.8 million from maturing auction rate securities. During 2006, we purchased $3,882.9 million of and received proceeds of $3,606.2 million from maturing auction rate securities.

During 2005, we purchased $77.0 million of auction rate securities. Auction rate securities are variable-rate debt securities. While the underlying security has a long-term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days.

Cash and cash equivalents at December 31, 2007 were $1,054.4 million and consisted primarily of commercial paper, money market funds invested in government securities and bank time deposits. Our short and long-term investment portfolios are invested in AAA rated non mortgage-backed auction rate securities. At December 31, 2007, we held $35.6 million of auction rate securities that were part of unsuccessful auctions. As a result of the unsuccessful auctions, the interest rate now resets every 28 days at one month LIBOR plus 50 basis points and the liquidity of these investments has been diminished. Based on our ability to access our cash and cash equivalents, our expected operating cash flows, and our other sources of cash including our credit facilities with commercial banks, we do not anticipate that the lack of liquidity on these investments will affect our ability to operate our business. These investments are classified as available-for-sale securities and are recorded at cost, which we believe approximates fair market value. At December 31, 2007, based on our ability and intent to hold such investments, all auction rate securities were classified as noncurrent investments. At December 31, 2006, all auction rate securities were classified as short-term investments. In September 2007, we discontinued additional investments in these types of securities.

Proceeds from disposal of assets were $178.8 million, $135.4 million and $90.1 million for 2007, 2006 and 2005, respectively. These disposals relate to rental tools that were lost-in-hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the year. Included in the proceeds for 2006 was $10.4 million, related to the sale of certain real estate properties held for sale.

During 2007, we received $9.9 million in proceeds from the sale of our equity investment in Toyo Petrolite Company Ltd. During 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash. WesternGeco also made a cash distribution of $59.6 million prior to closing. In 2005, we received distributions of $30.0 million from WesternGeco, which were recorded as a reduction in the carrying value of our investment. We also received $13.3 million from Schlumberger related to the WesternGeco true-up payment, of which $13.0 million was recorded as a reduction in the carrying value of our investment and $0.3 million as interest income.

In 2006, we received $46.3 million in net proceeds from the sale of certain businesses and our interest in an affiliate. Specifically, in March 2006, we completed the sale of Baker SPD and received $42.5 million in proceeds, and we received $3.8 million from the release of the remaining amount held in escrow related to our sale of Petreco International. In May 2005, we received $3.7 million from the initial release of this escrow.

During 2006, we paid $66.2 million for acquisitions of businesses, net of cash acquired. In the first quarter of 2006, we acquired Nova Technology Corporation (“Nova”) for $55.4 million, net of cash acquired of $3.0 million, plus assumed debt. In the second and third quarters of 2006, we made three acquisitions for $10.8 million, net of cash acquired of $0.7 million.

During 2005, we paid $46.8 million for acquisitions of businesses, net of cash acquired. In December, we purchased Zeroth Technology Limited (“Zertech”) for $20.3 million. In November, we paid $25.5 million, net of cash acquired of $1.7 million, for the remaining 50% interest in QuantX Wellbore Instrumentation (“QuantX”). During 2005, we also made smaller acquisitions having an aggregate purchase price of $1.0 million.

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.

Financing Activities

We had net (repayments) borrowings of commercial paper and other short-term debt of $14.2 million, $(8.8) million and $(71.1) million in 2007, 2006 and 2005, respectively. Total debt outstanding at December 31, 2007 was $1,084.8 million, an increase of $9.7 million compared with December 31, 2006. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.15 at December 31, 2007 and 0.17 at December 31, 2006.

In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. The interest rate swap agreement was designated and qualified as a fair value hedging instrument. Due to our outlook for interest rates, we terminated the interest rate swap agreement in June 2005, which required us to make a payment of $5.5 million. This amount was deferred and is being amortized as an increase to interest expense over the remaining life of the underlying debt security.

We received proceeds of $67.7 million, $92.5 million and $228.1 million in 2007, 2006 and 2005, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

Prior to our 2005 purchases, we had authorization remaining of $500.0 million to repurchase our common stock. During 2005, we repurchased 1.7 million shares of our common stock at an average price of $58.17 per share, for a total of $98.5 million. In April 2006, the Board of Directors authorized the repurchase of an additional $1.8 billion of common stock. During 2006, we repurchased 24.3 million shares of our common stock at an average price of $76.50 per share, for a total of $1,856.0 million. On July 26, 2007, our Board of Directors authorized a plan to repurchase up to $1.0 billion of our common stock, from time to time, in addition to the existing stock repurchase plan. During 2007, we repurchased 6.4 million shares of common stock at an average price of $81.25 per share for a total of $521.5 million. We had authorization remaining to repurchase approximately $824.0 million in common stock at the end of 2007.

We paid dividends of $166.2 million, $172.6 million and $161.1 million in 2007, 2006 and 2005, respectively.

Available Credit Facilities

At December 31, 2007, we had $1,018.5 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2012. The facility provides for a one year extension, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility) of less than or equal to 0.60, restrict certain merger transactions or the sale of all or substantially all of the assets of the Company or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At December 31, 2007, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the year ended December 31, 2007; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2007, we had no outstanding commercial paper.

If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit ratings. We do not have any ratings triggers in the facility that would accelerate the maturity of any borrowings under the facility. However, a downgrade in our credit ratings could increase the cost of borrowings under the facility and could also limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

We believe our credit ratings and relationships with major commercial and investment banks would allow us to obtain interim financing over and above our existing credit facilities for any currently unforeseen significant needs or growth opportunities. We also believe that such interim financings could be funded with subsequent issuances of long-term debt or equity, if necessary.

Cash Requirements

In 2008, we believe operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short-term and long-term operating strategies. We may incur short-term debt to fund expenses, capital expenditures and additional stock repurchases in the U.S. until cash can be cost effectively transferred to the U.S. from offshore. We may issue commercial paper or other short-term debt to fund cash needs in the U.S. in excess of the cash generated in the U.S.

In 2008, we expect capital expenditures to be approximately $1.3 billion excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations. In 2008, we also expect to make interest payments of between $73.0 million and $75.0 million, based on debt levels as of December 31, 2007. We anticipate making income tax payments of between $810.0 million and $860.0 million in 2008.

We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. Stock repurchases in 2008 (through February 19, 2008) were 8.0 million shares of common stock at an average price of $68.95 per share for a total of $551.8 million. As of February 19, 2008, we have authorization remaining to repurchase up to a total of $272.2 million of our common stock. We anticipate paying dividends of between $160.0 million and $165.0 million in 2008; however, the Board of Directors can change the dividend policy at anytime.

In the U.S., we merged two pension plans effective January 1, 2007, resulting in one tax-qualified U.S. pension plan, the Baker Hughes Incorporated Pension Plan (“BHIPP”). As a result of the merger of these plans, BHIPP is overfunded; therefore, we are not required nor do we intend to make pension contributions to BHIPP in 2008, and we currently estimate that we will not be required to make contributions to BHIPP for four to seven years thereafter. We do expect to contribute between $2.0 million and $3.0 million to our nonqualified U.S. pension plans and between $13.0 million and $15.0 million to the non-U.S. pension plans. We will also make benefit payments related to postretirement welfare plans of between $13.0 million and $15.0 million, and we estimate we will contribute between $142.0 million and $153.0 million to our defined contribution plans.

Other than as previously discussed, we do not believe there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than as previously discussed, we currently have no information that would create a reasonable likelihood that the reported levels of revenues and cash flows from operations in 2007 are not indicative of what we can expect in the near term.

Contractual Obligations

In the table below, we set forth our contractual cash obligations as of December 31, 2007. 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⁾	$	1,090.4	$	15.4	$	525.0	$	—	$	550.0
Estimated interest payments⁽²⁾		851.3		72.6		96.8		80.6		601.3
Operating leases⁽³⁾		377.3		95.0		108.1		51.2		123.0
Purchase obligations⁽⁴⁾		293.1		252.0		27.1		14.0		—
Other long-term liabilities⁽⁵⁾		96.4		25.4		53.2		3.3		14.5
FIN 48 tax liabilities⁽⁶⁾		456.9		105.5		119.0		206.2		26.2

Total	$	3,165.4	$	565.9	$	929.2	$	355.3	$	1,315.0


⁽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 would change if we exercised these renewal options and if we entered into additional operating lease agreements.

⁽⁴⁾		Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable at anytime without penalty.

⁽⁵⁾		Amounts represent other long-term liabilities, including the current portion, reflected in the consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions and payments for various postretirement welfare benefit plans and postemployment benefit plans.

⁽⁶⁾		The estimated FIN 48 tax liabilities will be settled as a result of expiring statutes, audit activity, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

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 $466.8 million at December 31, 2007. We also had commitments outstanding for purchase obligations related to capital expenditures and inventory under purchase orders and contracts of approximately $293.1 million at December 31, 2007. It is not practicable to estimate the fair value of these financial instruments. None of the off-balance sheet arrangements either has, or is likely to have, a material effect on our consolidated financial statements.

Other than normal operating leases, we do not have any off-balance sheet financing arrangements such as securitization agreements, liquidity trust vehicles, synthetic leases or special purpose entities. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

CRITICAL ACCOUNTING ESTIMATES

The preparation of our consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures and about contingent assets and liabilities. We base these estimates and judgments on historical experience and other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty, and accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.

We have defined a critical accounting estimate as one that is both important to the portrayal of either our financial condition or results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We have discussed the development and selection of our critical accounting estimates with the Audit/Ethics Committee of our Board of Directors and the Audit/Ethics Committee has reviewed the disclosure presented below. During the past three fiscal years, we have not made any material changes in the methodology used to establish the critical accounting estimates discussed below, except as required by the adoption of FIN 48. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation but are not deemed critical as defined above.

Allowance for Doubtful Accounts

The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2007 and 2006, allowance for doubtful accounts totaled $59.0 million, or 2.4%, and $50.5 million, or 2.4%, of total gross accounts receivable, respectively. We believe that our allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had an impact on income from continuing operations before income taxes of approximately $3.0 million in 2007.

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, 2007 and 2006, inventory reserves totaled $221.2 million, or 11.3%, and $211.7 million, or 12.2%, of gross inventory, respectively. We believe that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes to our estimates and forecasts could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had an impact on income from continuing operations before income taxes of approximately $11.1 million in 2007.

Impairment of Long-Lived Assets

Long-lived assets, which include property, goodwill, intangible assets, investments in affiliates and certain other assets, comprise a significant amount of our total assets. We review the carrying values of these assets for impairment periodically, and at least annually for goodwill, or whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review. In turn, these forecasts are uncertain in that they require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions; however, based upon our evaluation of the current business climate in which we operate, we do not currently anticipate that any significant asset impairment losses will be necessary in the foreseeable future.

Income Taxes

The liability method is used for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, we have considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets. Historically, changes to valuation allowances have been caused by major changes in the business cycle in certain countries and changes in local country law. The ultimate realization of the deferred tax assets depends on the generation of sufficient taxable income in the applicable taxing jurisdictions.

We operate in more than 90 countries under many legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Our operations in these different jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each taxing jurisdiction could have an impact on the amount of income taxes that we provide during any given year.

Our tax filings for various periods are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings consistent with the requirements of FIN 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(“FIN 48”). The resulting change to our tax liability, if any, is dependent on numerous factors that are difficult to estimate. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued.

In addition to the aforementioned assessments that have been received from various tax authorities, we provide for taxes for uncertain tax positions where assessments have not been received in accordance with FIN 48. We believe such tax reserves are adequate in relation to the potential for additional assessments. Once established, we adjust these amounts only when more information is available or when an event occurs necessitating a change to the reserves. Future events such as changes in the facts or law, judicial decisions regarding the application of existing law or a favorable audit outcome will result in changes to the amounts provided. We believe that the resolution of tax matters will not have a material effect on the consolidated financial condition of the

Company, although a resolution could have a material impact on our consolidated statement of operations for a particular period and on our effective tax rate for any period in which such resolution occurs.

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 6.0% in 2007, 5.5% in 2006 and 6.0% in 2005 to determine plan expenses. A 50 basis point reduction in the discount rate would have decreased income from continuing operations before income taxes by approximately $3.3 million in 2007.

To determine the expected rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets. A lower rate of return increases plan expenses. We assumed rates of return on our plan investments were 8.5% in 2007, 2006 and 2005. A 50 basis point reduction in the expected rate of return on assets of our principal plans would have decreased income from continuing operations before income taxes by approximately $3.4 million in 2007.

DISCONTINUED OPERATIONS

In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“Baker SPD”), a product line group within the Completion and Production segment, which distributes basic supplies, products and small tools to the drilling industry. In March 2006, we completed the sale of Baker SPD and received cash proceeds of $42.5 million. We recorded a gain on the sale of $19.2 million, net of tax of $11.0 million, which consisted of an after-tax gain on the disposal of $16.9 million and $2.3 million related to the recognition of the cumulative foreign currency translation adjustments into earnings.

We have reclassified the consolidated financial statements for all prior periods presented to reflect this operation as discontinued. See Note 2 of the Notes to Consolidated Financial Statements in Item 8 herein for additional information regarding discontinued operations.

NEW ACCOUNTING STANDARDS

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) SFAS No. 155,Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and No. 140(“SFAS 155”). SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. We adopted SFAS 155 on January 1, 2007, and there was no impact on our consolidated financial statements.

In July 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. It prescribes the minimum threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted FIN 48 on January 1, 2007 as required, and recorded a reduction to beginning retained earnings of $64.2 million. See Note 6 for further information.

planned major maintenance activities in annual and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007 to change our method of accounting for repairs and maintenance activities on certain rental tools from the accrue-in-advance method to the direct expense method. The adoption resulted in the reversal of a $34.2 million accrued liability for future repairs and maintenance (“R&M”) costs and the recording of an income tax liability of $9.0 million. The net impact of $25.2 million has been recorded as an increase to beginning retained earnings as of January 1, 2007. We did not restate any prior periods as the impact was not material to our financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements(“SFAS 157”), which is intended to increase consistency and comparability in fair value measurements by defining fair value, establishing a framework for measuring fair value and expanding disclosures about fair value measurements. SFAS 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In November 2007, the FASB placed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities; however, SFAS 157 is effective for fiscal years beginning after November 15, 2007 for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements. We adopted SFAS 157 on January 1, 2008 for financial assets and liabilities, as well as for any other assets and liabilities that are carried at fair value on a recurring basis in financial statements, with no impact on our consolidated financial statements. We will begin the new disclosure requirements in the first quarter of 2008.

In September 2006, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans–an amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS 158”). SFAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. Additionally, it requires an employer to measure the funded status of a plan as of the date of its year end statement of financial position, with limited exceptions. SFAS 158 is effective as of the end of the fiscal year ending after December 15, 2006; however, the requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year end statement of financial position is effective for fiscal years ending after December 15, 2008. We adopted all requirements of SFAS 158 on December 31, 2006, except for the funded status measurement date requirement, which will be adopted on December 31, 2008, as allowed under SFAS 158. We currently do not expect there to be a material impact on our consolidated financial statements as a result of the adoption of the funded status measurement date requirement.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115(“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS 159 on January 1, 2008. We will continue to evaluate the application of SFAS 159, and we currently do not expect there to be a material, if any, impact on our consolidated financial statements as a result of this adoption.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS 160 on January 1, 2009, and have not yet determined the impact, if any, on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations(“SFAS 141R”). SFAS 141R replaces FASB Statement No. 141,Business Combinations. The statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be expensed. In addition, the statement requires disclosures to enable users to evaluate the nature and financial effects of the business combination. SFAS 141 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We will adopt SFAS 141R on January 1, 2009 for acquisitions on or after this date.

RELATED PARTY TRANSACTIONS

In November 2000, we entered into an agreement with WesternGeco, whereby WesternGeco subleases a facility from us for a period of ten years at then current market rates. In 2006, we entered into an extension of the sublease for five additional years with rent to be determined based on market rates in 2010. During 2006 and 2005, we received payments of $5.6 million and $6.5 million, respectively, from WesternGeco related to this lease. On April 28, 2006, we sold our 30% interest in WesternGeco for $2.4 billion in cash and recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, after-tax). Beginning in 2007, WesternGeco is no longer

considered a related party.

During 2006 and 2005, we received distributions of $59.6 million and $30.0 million, respectively, from WesternGeco, which were recorded as reductions in the carrying value of our investment.

During 2005, we received $13.3 million from Schlumberger related to a true-up payment associated with revenues earned by WesternGeco during the four year period ending November 2004 from each party’s contributed multiclient seismic data libraries. We recorded $13.0 million as a reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest income. The income tax effect of $3.3 million related to this payment is included in our provision for income taxes for the year ended December 31, 2005.

There were no other significant related party transactions.

FORWARD-LOOKING STATEMENTS

MD&A and certain statements in the Notes to Consolidated Financial Statements include forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act (each a “forward-looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward-looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of any common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Risk Factors Related to Our Business” sections contained in Item 1A. Risk Factors and those set forth from time to time in our filings with the SEC. These documents are available through our web site or through the SEC’s Electronic Data Gathering and Analysis Retrieval System (“EDGAR”) athttp://www.sec.gov.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

For discussion of our risk factors and cautions regarding forward-looking statements, see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 7, both contained herein. The risk factors discussed there are not intended to be all inclusive.

Risk Factors Related to Our Business

For discussion of our risk factors and cautions regarding forward-looking statements, see the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section, both contained herein. This list of risk factors is not intended to be all inclusive.


ITEM 7A.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks that are inherent in our financial instruments and arise from changes in interest rates and foreign currency exchange rates. We may enter into derivative financial instrument transactions to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative purposes. A discussion of our primary market risk exposure in financial instruments is presented below.

INTEREST RATE RISK AND INDEBTEDNESS

We are subject to interest rate risk on our long-term fixed interest rate debt. Commercial paper borrowings, other short-term borrowings and variable rate long-term debt do not give rise to significant interest rate risk because these borrowings either have maturities of less than three months or have variable interest rates similar to the interest rates we receive on our short-term investments. All other things being equal, the fair market value of debt with a fixed interest rate will increase as interest rates fall and

will decrease as interest rates rise. This exposure to interest rate risk is managed by borrowing money that has a variable interest rate or using interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.

At December 31, 2007 and at December 31, 2006, there were no interest rate swap agreements in effect.

We had fixed rate debt aggregating $1,075.0 million at December 31, 2007 and 2006. 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, 2007 and 2006 (dollar amounts in millions).


	2007		2008		2009			2010		2011		2012		Thereafter			Total

As of December 31, 2007:
Long-term debt^{(1) (2)}	$	—	$	—	$	525.0		$	—	$	—	$	—	$	550.0		$	1,075.0
Weighted average effective interest rates						5.24	%⁽³⁾								7.54	%		6.40	%⁽³⁾

As of December 31, 2006:
Long-term debt^{(1) (2)}	$	—	$	—	$	525.0		$	—	$	—	$	—	$	550.0		$	1,075.0
Weighted average effective interest rates						5.22	%⁽³⁾								7.55	%		6.39	%⁽³⁾


⁽¹⁾		Amounts do not include any unamortized discounts, deferred issuance costs or net deferred gains on terminated interest rate swap agreements.

⁽²⁾		Fair market value of fixed rate long-term debt was $1,154.3 million at December 31, 2007 and $1,169.7 million at December 31, 2006.

⁽³⁾		Includes the effect of the amortization of net deferred gains on terminated interest rate swap agreements.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

We conduct operations around the world in a number of different currencies. A number of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to fluctuations in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency. To the extent that market conditions and/or local regulations prevent us from maintaining a minimal consolidated net asset or net liability position, we may enter into foreign currency forward contracts or option contracts.

At December 31, 2007, we had entered into several foreign currency forward contracts with notional amounts aggregating $115.0 million to hedge exposure to currency fluctuations in various foreign currency denominated accounts payable and accounts receivable, including the British Pound Sterling, Norwegian Krone, Euro and the Brazilian Real. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we recorded a gain of $1.1 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign currency exchange losses resulting from the underlying exposures and is included in marketing, general and administrative expense in the consolidated statement of operations.

At December 31, 2007, we had entered into option contracts with notional amounts aggregating $20.0 million as a hedge of fluctuations in the Russian Ruble exchange rate. The contracts were not designated as hedging instruments. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we recorded a loss of $0.3 million to adjust the carrying value of these contracts to their fair market value. This loss is included in marketing, general and administrative expense in our consolidated statement of operations.

At December 31, 2006, we had entered into several foreign currency forward contracts with notional amounts aggregating $105.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including British Pound Sterling, Norwegian Krone, Euro, Indonesian Rupiah and Brazilian Real. These contracts were designated and qualified as fair value hedging instruments. Based on quoted market prices as of December 31, 2006 for contracts with similar terms and maturity dates, we recorded a loss of $0.2 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign currency exchange gains resulting from the underlying exposures and is included in marketing, general and administrative expense in the consolidated statement of operations.

The counterparties to our foreign currency forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency exchange rate differential.


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 inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our evaluation under the framework inInternal 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, 2007. 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 19, 2008

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, 2007, based on criteria established inInternal Control-Integrated Frameworkissued 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, 2007, based on the criteria established inInternal Control-Integrated Frameworkissued 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 as of and for the year ended December 31, 2007 of the Company and our report dated February 19, 2008 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the Company’s adoption of new accounting standards.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 19, 2008

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, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As described in Note 1 and Note 6 to the consolidated financial statements: effective as of January 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) AUG AIR-1, which prohibits the accrue-in-advance method of accounting for planned major maintenance activities; effective as of January 1, 2007, the Company adopted FASB Interpretation 48, which established new accounting and reporting standards for uncertainty in income taxes recognized in financial statements. Furthermore, as described in Note 4 and Note 14 to the consolidated financial statements: effective as of January 1, 2006, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123R, which established new accounting and reporting standards for stock-based compensation; effective as of December 31, 2006, the Company adopted SFAS No. 158, which established new accounting and reporting standards for defined benefit pension and other postretirement plans.

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, 2007, based on the criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 19, 2008

Baker Hughes Incorporated
Consolidated Statements of Operations
(In millions, except per share amounts)


	Year Ended December 31,
	2007			2006			2005

Revenues:
Sales	$	5,170.7		$	4,566.1		$	3,738.2
Services and rentals		5,257.5			4,461.3			3,447.3

Total revenues		10,428.2			9,027.4			7,185.5


Costs and expenses:
Cost of sales		3,517.3			3,033.0			2,580.0
Cost of services and rentals		3,328.3			2,843.4			2,443.7
Research and engineering		372.0			338.9			299.6
Marketing, general and administrative		932.8			877.8			628.8

Total costs and expenses		8,150.4			7,093.1			5,952.1


Operating income		2,277.8			1,934.3			1,233.4
Equity in income of affiliates		1.2			60.4			100.1
Gain on sale of interest in affiliate		—			1,743.5			—
Interest expense		(66.1	)		(68.9	)		(72.3	)
Interest and dividend income		43.8			67.5			18.0


Income from continuing operations before income taxes		2,256.7			3,736.8			1,279.2
Income taxes		(742.8	)		(1,338.2	)		(404.8	)


Income from continuing operations		1,513.9			2,398.6			874.4
Income from discontinued operations, net of tax		—			20.4			4.9

Income before cumulative effect of accounting change		1,513.9			2,419.0			879.3
Cumulative effect of accounting change, net of tax		—			—			(0.9	)

Net income	$	1,513.9		$	2,419.0		$	878.4


Basic earnings per share:
Income from continuing operations	$	4.76		$	7.26		$	2.58
Income from discontinued operations		—			0.06			0.01
Cumulative effect of accounting change		—			—			—

Net income	$	4.76		$	7.32		$	2.59


Diluted earnings per share:
Income from continuing operations	$	4.73		$	7.21		$	2.56
Income from discontinued operations		—			0.06			0.01
Cumulative effect of accounting change		—			—			—

Net income	$	4.73		$	7.27		$	2.57

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Balance Sheets
(In millions, except per value)


	December 31,
	2007			2006

ASSETS
Current Assets:
Cash and cash equivalents	$	1,054.4		$	750.0
Short-term investments		—			353.7
Accounts receivable – less allowance for doubtful accounts:
December 31, 2007, $59.0; December 31, 2006, $50.5		2,382.9			2,055.1
Inventories		1,714.4			1,528.8
Deferred income taxes		181.5			167.8
Other current assets		122.4			112.4

Total current assets		5,455.6			4,967.8

Property, plant and equipment – less accumulated depreciation:
December 31, 2007, $2,976.4; December 31, 2006, $2,713.4		2,344.6			1,800.5	��
Goodwill		1,354.2			1,347.0
Intangible assets – less accumulated amortization:
December 31, 2007, $124.1; December 31, 2006, $102.3		176.6			190.4
Other assets		525.6			400.0

Total assets	$	9,856.6		$	8,705.7


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	704.2		$	648.8
Short-term borrowings and current portion of long-term debt		15.4			1.3
Accrued employee compensation		456.8			484.2
Income taxes payable		190.9			150.0
Other accrued liabilities		250.6			337.6

Total current liabilities		1,617.9			1,621.9

Long-term debt		1,069.4			1,073.8
Deferred income taxes and other tax liabilities		415.6			300.2
Liabilities for pensions and other postretirement benefits		332.1			339.3
Other liabilities		116.0			127.6
Commitments and contingencies

Stockholders’ Equity:
Common stock, one dollar par value (shares authorized – 750.0; issued and outstanding – 315.4 at December 31, 2007 and 319.9 at December 31, 2006)		315.4			319.9
Capital in excess of par value		1,216.1			1,600.6
Retained earnings		4,818.3			3,509.6
Accumulated other comprehensive loss		(44.2	)		(187.2	)

Total stockholders’ equity		6,305.6			5,242.9

Total liabilities and stockholders’ equity	$	9,856.6		$	8,705.7

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Stockholders’ Equity
(In millions, except per share amounts)


				Capital						Accumulated
				in Excess						Other
	Common			of			Retained			Comprehensive			Unearned
	Stock			Par Value			Earnings			Loss			Compensation			Total

Balance, December 31, 2004	$	336.6		$	3,127.8		$	545.9		$	(109.8	)	$	(5.1	)	$	3,895.4
Comprehensive income:
Net income								878.4
Foreign currency translation adjustments, net of tax of $0.1											(65.0	)
Change in minimum pension liability, net of tax of $5.5											(12.2	)
Other											(1.0	)
Total comprehensive income																	800.2
Issuance of restricted stock net of cancellations, net of tax of $6.6		0.4			19.2									(12.3	)		7.3
Amortization of unearned compensation, net of tax of $(2.1)														5.0			5.0
Stock issued pursuant to employee stock plans, net of tax of $19.8		6.2			243.3												249.5
Repurchase and retirement of common stock		(1.7	)		(96.8	)											(98.5	)
Cash dividends ($0.475 per share)								(161.1	)								(161.1	)

Balance, December 31, 2005	$	341.5		$	3,293.5		$	1,263.2		$	(188.0	)	$	(12.4	)	$	4,697.8
Comprehensive income:
Net income								2,419.0
Foreign currency translation adjustments:
Reclassifications included in net income due to sale of business											(2.3	)
Translation adjustments, net of tax of $4.3											59.4
Change in minimum pension liability, net of tax of $7.0											(17.8	)
Other											1.1
Total comprehensive income																	2,459.4
Adoption of SFAS 158, net of tax of $21.6											(39.6	)					(39.6	)
Adoption of SFAS 123(R)					(12.4	)								12.4
Issuance of restricted stock, net of cancellations		0.2			15.1												15.3
Issuance of common stock pursuant to employee stock plans		2.4			97.8												100.2
Tax benefit on stock plans					17.6												17.6
Stock-based compensation					20.7												20.7
Repurchase and retirement of common stock		(24.2	)		(1,831.7	)											(1,855.9	)
Cash dividends ($0.52 per share)								(172.6	)								(172.6	)

Balance, December 31, 2006	$	319.9		$	1,600.6		$	3,509.6		$	(187.2	)	$	—		$	5,242.9
Adoption of AUG AIR-1, net of tax of $(9.0)								25.2									25.2
Adoption of FIN 48								(64.2	)								(64.2	)

Adjusted beginning balance January 1, 2007	$	319.9		$	1,600.6		$	3,470.6		$	(187.2	)	$	—		$	5,203.9
Comprehensive income:
Net income								1,513.9
Foreign currency translation adjustments, net of tax of $(7.3)											72.2
Defined benefit pension plans, net of tax of $(37.4)											70.8
Total comprehensive income																	1,656.9
Issuance of restricted stock, net of cancellations		0.2			14.4												14.6
Issuance of common stock, pursuant to employee stock plans		1.7			65.8												67.5
Tax benefit on stock plans					18.5												18.5
Stock-based compensation					31.9												31.9
Repurchase and retirement of common stock		(6.4	)		(515.1	)											(521.5	)
Cash dividends ($0.52 per share)								(166.2	)								(166.2	)

Balance, December 31, 2007	$	315.4		$	1,216.1		$	4,818.3		$	(44.2	)	$	—		$	6,305.6

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Consolidated Statements of Cash Flows
(In millions)


	Year Ended December 31,
	2007			2006			2005

Cash flows from operating activities:
Income from continuing operations	$	1,513.9		$	2,398.6		$	874.4
Adjustments to reconcile income from continuing operations to net cash flows from operating activities:
Depreciation and amortization		521.2			433.7			382.4
Amortization of net deferred gains on derivatives		(5.1	)		(5.1	)		(5.7	)
Stock-based compensation costs		50.9			46.0			9.2
Acquired in-process research and development		—			2.6			5.1
(Benefit)/provision for deferred income taxes		(3.7	)		77.7			7.4
Gain on sale of interest in affiliate		—			(1,743.5	)		—
Provision for income taxes on gain on sale of interest in affiliate		—			708.3			—
Gain on disposal of assets		(78.8	)		(59.2	)		(34.8	)
Equity in income of affiliates		(1.2	)		(60.4	)		(100.1	)
Changes in operating assets and liabilities:
Accounts receivable		(287.3	)		(316.4	)		(329.4	)
Inventories		(141.8	)		(364.9	)		(108.7	)
Accounts payable		25.9			69.1			122.3
Accrued employee compensation and other accrued liabilities		(138.9	)		104.1			92.4
Income taxes payable		129.1			(98.0	)		54.9
Income taxes paid on sale of interest in affiliate		(125.3	)		(555.1	)		—
Liabilities for pensions and other postretirement benefits and other liabilities		(4.3	)		57.4			41.7
Other		20.1			(105.2	)		(61.5	)

Net cash flows from continuing operations		1,474.7			589.7			949.6
Net cash flows from discontinued operations		—			0.4			5.8

Net cash flows from operating activities		1,474.7			590.1			955.4


Cash flows from investing activities:
Expenditures for capital assets		(1,127.0	)		(922.2	)		(478.3	)
Purchase of short-term investments		(2,520.7	)		(3,882.9	)		(77.0	)
Proceeds from maturities of short-term investments		2,838.8			3,606.2			—
Proceeds from disposal of assets		178.8			135.4			90.1
Proceeds from sale of interests in affiliates		9.9			2,400.0			—
Acquisition of businesses, net of cash acquired		—			(66.2	)		(46.8	)
Distributions from affiliates		—			59.6			30.0
Receipt of true-up payment related to affiliate		—			—			13.0
Proceeds from sale of business		—			46.3			3.7

Net cash flows from continuing operations		(620.2	)		1,376.2			(465.3	)
Net cash flows from discontinued operations		—			—			(0.1	)

Net cash flows from investing activities		(620.2	)		1,376.2			(465.4	)


Cash flows from financing activities:
Net (repayments) borrowings of commercial paper and other short-term debt		14.2			(8.8	)		(71.1	)
Payment to terminate interest rate swap agreement		—			—			(5.5	)
Proceeds from issuance of common stock		67.7			92.5			228.1
Repurchase of common stock		(521.5	)		(1,856.0	)		(98.5	)
Dividends		(166.2	)		(172.6	)		(161.1	)
Excess tax benefits from stock-based compensation		13.8			18.5			—

Net cash flows from financing activities		(592.0	)		(1,926.4	)		(108.1	)

Effect of foreign exchange rate changes on cash		41.9			13.1			(3.9	)

Increase in cash and cash equivalents		304.4			53.0			378.0
Cash and cash equivalents, beginning of year		750.0			697.0			319.0

Cash and cash equivalents, end of year	$	1,054.4		$	750.0		$	697.0


Income taxes paid	$	716.7		$	1,197.5		$	299.7
Interest paid	$	75.9		$	74.4		$	80.8

See Notes to Consolidated Financial Statements

Baker Hughes Incorporated
Notes to Consolidated Financial Statements

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Baker Hughes Incorporated (“Baker Hughes”) is engaged in the oilfield services industry. Baker Hughes is a major supplier of products and technology services and systems to the worldwide oil and natural gas industry and provides products and services for drilling, formation evaluation, completion and production of oil and natural gas wells.

Basis of Presentation

The consolidated financial statements include the accounts of Baker Hughes and all majority owned subsidiaries (“Company,” “we,” “our” or “us”). Investments over which we have the ability to exercise significant influence over operating and financial policies, but do not hold a controlling interest, are accounted for using the equity method of accounting. All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in millions of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. Estimates are used for, but are not limited to, determining the following: allowance for doubtful accounts and inventory valuation reserves, recoverability of long-lived assets, useful lives used in depreciation and amortization, income taxes and related valuation allowances and insurance, environmental, legal and pensions and postretirement benefit obligations.

Revenue Recognition

Our products and services are generally sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not include right of return or other similar provisions or other significant post-delivery obligations. Our products are produced in a standard manufacturing operation, even if produced to our 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.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

Investments

Prior to September 2007, we invested in auction rate securities, which are variable-rate debt securities. While the underlying security has a long-term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days. The securities trade at par and are callable at par on any interest payment date at the option of the issuer. Interest is paid at the end of each auction period. We limited our investments in auction rate securities to non mortgage-backed securities that carry a AAA (or equivalent) rating from a recognized rating agency. The investments are classified as available-for-sale and are recorded at cost, which we believe approximates fair market value. At December 31, 2007, we held $35.6 million of auction rate securities that were part of unsuccessful auctions. As a result of the unsuccessful auctions, the interest rate now resets every 28 days at one month LIBOR plus 50 basis points and the liquidity of these investments has been diminished. At December 31, 2007, based on our ability and intent

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

to hold such investments, we have classified all investments in auction rate securities totaling $35.6 million as noncurrent investments, which are included in other assets in our consolidated balance sheet. At December 31, 2006, these investments were classified as short-term 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. The capitalized costs of computer software developed or purchased for internal use are classified in machinery and equipment in PP&E.

Goodwill, Intangible Assets and Amortization

Goodwill, including goodwill associated with equity method investments, and intangible assets with indefinite lives are not amortized. Intangible assets with finite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized.

Impairment of Long-Lived Assets

We review property, intangible assets and certain other assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The determination of recoverability is made based upon the estimated undiscounted future net cash flows, excluding interest expense. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related assets.

We perform an annual impairment test of goodwill for each of our reporting units as of October 1, or more frequently if circumstances indicate an impairment may exist. Our reporting units are based on our organizational and reporting structure. Corporate and other assets and liabilities are allocated to the reporting units to the extent that they relate to the operations of those reporting units in determining their carrying amount. Investments in affiliates are also reviewed for impairment whenever events or changes in circumstances indicate that impairment may exist. The determination of impairment is made by comparing the carrying amount with its fair value, which is calculated using a combination of a market capitalization and discounted cash flow approach.

Income Taxes

We use the liability method for determining our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Future tax benefits are recognized to the extent that realization of such benefits is more likely than not.

Deferred income taxes are provided for the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities. Deferred tax assets are also provided for certain tax credit carryforwards. A valuation allowance to reduce deferred tax assets is established when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

We intend to indefinitely reinvest certain earnings of our foreign subsidiaries in operations outside the U.S., and accordingly, we have not provided for U.S. income taxes on such earnings. We do provide for the U.S. and additional non-U.S. taxes on earnings anticipated to be repatriated from our non-U.S. subsidiaries.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

jurisdictions are taxed on various bases: actual income before taxes, deemed profits (which are generally determined using a percentage of revenues rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions or our level of operations or profitability in each tax jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.

Our tax filings for various periods are subjected to audit by tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various tax authorities and are currently at varying stages of appeals and/or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable. We provide for uncertain tax positions pursuant to FIN 48,Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109.

Product Warranties

We sell certain products with a product warranty that provides that customers can return a defective product during a specified warranty period following the purchase in exchange for a replacement product, repair at no cost to the customer or the issuance of a credit to the customer. We accrue amounts for estimated warranty claims based upon current and historical product sales data, warranty costs incurred and any other related information known to us.

Environmental Matters

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. Such accruals are recorded when it is probable that we will be obligated to pay for environmental site evaluation, remediation or related activities, and such costs can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. As additional or more accurate information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred. Where we have been identified as a potentially responsible party in a United States federal or state “Superfund” site, we accrue our share of the estimated remediation costs of the site. This share is based on the ratio of the estimated volume of waste we contributed to the site to the total volume of waste disposed at the site.

Foreign Currency

A number of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non-functional currency, are included in marketing, general and administrative (“MG&A”) expense in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and losses resulting from balance sheet translation of foreign operations are also included in MG&A expense in the consolidated statements of operations as incurred. We recorded net foreign currency transaction and translation gains in MG&A in the consolidated statement of operations of $10.7 million, $1.7 million and $6.8 million in 2007, 2006 and 2005, respectively.

Derivative Financial Instruments

We monitor our exposure to various business risks including commodity prices, foreign currency exchange rates and interest rates and occasionally use derivative financial instruments to manage the impact of certain of these risks. Our policies do not permit the use of derivative financial instruments for speculative purposes. We use foreign currency forward contracts to hedge certain firm commitments and transactions denominated in foreign currencies. We have used and may use interest rate swaps to manage interest rate risk.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

At the inception of any new derivative, we designate the derivative as a hedge as that term is defined in SFAS 133 (as amended and interpreted)Accounting for Derivative Instruments and Hedging Activitiesor 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.

Reclassifications

New Accounting Standards

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 155,Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and No. 140(“SFAS 155”). SFAS 155 amends SFAS 133, which required that a derivative embedded in a host contract that does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS 155 is effective for all financial instruments acquired or issued (or subject to a remeasurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. We adopted SFAS 155 on January 1, 2007, and there was no impact on our consolidated financial statements.

In September 2006, the FASB issued FASB Staff Position No. AUG AIR-1 (“FSP AUG AIR-1”), which addresses the accounting for planned major maintenance activities. FSP AUG AIR-1 prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. We adopted FSP AUG AIR-1 on January 1, 2007 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 the reversal of a $34.2 million accrued liability for future repairs and maintenance (“R&M”) costs and the recording of an income tax liability of $9.0 million. The net impact of $25.2 million has been recorded as an increase to beginning retained earnings as of January 1, 2007. We did not restate any prior periods as the impact was not material to our financial statements.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 2. DISCONTINUED OPERATIONS

We have reclassified the consolidated financial statements for all prior periods presented to reflect these operations as discontinued. Summarized financial information from discontinued operations is as follows for the years ended December 31:


	2007		2006			2005

Revenues	$	—	$	6.7		$	32.5


Income before income taxes	$	—	$	1.8		$	7.7
Income taxes		—		(0.6	)		(2.8	)

Income before gain on disposal		—		1.2			4.9
Gain on disposal, net of tax		—		19.2			—

Income from discontinued operations	$	—	$	20.4		$	4.9

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 3. ACQUISITIONS

In January 2006, we acquired Nova Technology Corporation (“Nova”) for $55.4 million, net of cash acquired of $3.0 million, plus assumed debt. Nova is a supplier of permanent monitoring, chemical injection systems, and multi-line services for deepwater and subsea oil and gas well applications. As a result of the acquisition, we recorded $29.7 million of goodwill, $24.3 million of intangible assets and assigned $2.6 million to in-process research and development. Under the terms of the purchase agreement, the former owners of Nova are entitled to additional purchase price consideration of up to $3.0 million based on certain post-closing events to the extent that those events occur no later than January 31, 2016, of which $1.0 million was paid during 2007.

In December 2005, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million in cash. As a result of the acquisition, we recorded $9.4 million of goodwill and $10.3 million of intangible assets. Under the terms of the purchase agreement, the former owners of Zertech are entitled to additional purchase price consideration of up to approximately $14.0 million based on the performance of the business during 2006, 2007 and 2008.

We owned a 50% interest in the QuantX Wellbore Instrumentation venture (“QuantX”) and in October 2005, we purchased the remaining 50% interest in QuantX for $27.2 million. We recorded $28.4 million of goodwill, $19.6 million of intangibles and assigned $5.1 million to in-process research and development.

All acquisitions above are included in the Completion and Production segment. For each of these acquisitions, the purchase price was allocated based on the fair value of the assets acquired and liabilities assumed using a discounted cash flow approach. Amounts related to in-process research and development were written off at the date of acquisition and are included in research and engineering expenses. Pro forma results of operations have not been presented individually or in the aggregate for these acquisitions because the effects of these acquisitions were not material to our consolidated financial statements.

NOTE 4. STOCK-BASED COMPENSATION

On January 1, 2006, we adopted SFAS 123(R), which establishes accounting for equity instruments exchanged for employee services. SFAS 123(R) is a revision of SFAS 123 and supersedes APB 25. Under the provisions of SFAS 123(R), stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense over the employee’s service period, which is generally the vesting period of the equity grant.

Prior to January 1, 2006, we accounted for stock-based compensation to employees under the intrinsic value method in accordance with APB 25, as permitted under SFAS 123. Under this method, compensation cost was recognized for the difference between the quoted market price of our common stock on the date of grant and the amount, if any, the employee was required to pay for the common stock (the exercise price). Accordingly, we did not recognize compensation cost for our stock option awards or our employee stock purchase plan because we issue options at exercise prices equal to the market value of our stock on the date of grant and because our employee stock purchase plan was noncompensatory. We did record compensation cost for our restricted stock awards and restricted stock units.

We adopted SFAS 123(R) using the modified prospective application method and, accordingly, no prior periods have been restated. Under this method, compensation cost recognized during the year ended December 31, 2006 includes: (a) compensation cost for all stock-based awards granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123, and (b) compensation cost for all stock-based awards granted after January 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123(R). Additionally, compensation cost is recognized based on awards ultimately expected to vest, therefore, we have reduced the cost for estimated forfeitures based on historical forfeiture rates. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. As a result of the adoption of SFAS 123(R), the balance in unearned compensation recorded in stockholders’ equity as of January 1, 2006, of $12.4 million, net of tax, was reclassified to and reduced the balance of capital in excess of par value.

The FASB Staff Position No. FAS 123 (R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards” (“FSP 123(R)-3”), provides an alternative method of calculating excess tax benefits (the “APIC pool”) from the method defined in SFAS 123(R). A one-time election to adopt the transition method in FSP 123(R)-3 is available to those entities adopting SFAS 123(R). The Company has calculated the APIC pool using the alternative method outlined in FSP 123(R)-3.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The following table summarizes stock-based compensation costs recognized under SFAS 123(R) for the years ended December 31, 2007 and 2006 and under APB 25 for the year ended December 31, 2005. There were no stock-based compensation costs capitalized as the amounts were not material.


	2007			2006			2005

Stock-based compensation costs	$	50.9		$	46.0		$	9.2
Tax benefit		(11.4	)		(10.1	)		(3.1	)

Stock-based compensation costs, net of tax	$	39.5		$	35.9		$	6.1

For our stock options and restricted stock awards and units, we currently have 30.0 million shares authorized for issuance and as of December 31, 2007, approximately 7.5 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.

The following table illustrates the pro forma effect on net income and earnings per share for the year ended December 31, 2005 if we had recognized compensation expense by applying the fair value based method to all awards as provided for under SFAS 123:


	2005

Net income, as reported	$	878.4
Add: Stock-based compensation for restricted stock awards and units included in reported net income, net of tax		6.1
Deduct: Stock-based compensation determined under SFAS 123, net of tax		(35.0	)

Pro forma net income	$	849.5


Basic EPS:
As reported	$	2.59
Pro forma		2.50
Diluted EPS:
As reported	$	2.57
Pro forma		2.49

Stock Options

Our stock option plans provide for the issuance of incentive and non-qualified stock options to directors, officers and other key employees at an exercise price equal to the fair market value of the stock at the date of grant. Although subject to the terms of the stock option agreement, substantially all of the stock options become exercisable in three equal annual installments, beginning a year from the date of grant, and generally expire ten years from the date of grant. The stock option plans provide for the acceleration of vesting upon the 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 on the date of grant using the Black-Scholes option pricing model. The following table presents the weighted average assumptions used in the option pricing model for options granted. The expected life of the options represents the period of time the options are expected to be outstanding. For the year 2005, the expected life was based on historical trends. For the years ended December 31, 2007 and 2006, the expected life is based on our historical exercise trends and post-vest termination data incorporated into a forward–looking stock price model. For the year 2005, our expected volatility is based on the historical volatility of our stock for a period approximating the expected life. For the years ended December 31, 2007 and 2006, as allowed under the Securities and Exchange Commission’s Staff Accounting Bulletin 107 (“SAB 107”), the expected volatility is based on our implied volatility, which is the volatility forecast that is implied by the prices of our actively traded options to purchase our stock observed in the market. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on our history of dividend payouts.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)


	2007			2006			2005
	Actual			Actual			Pro Forma

Expected life (years)		5.1			5.0			3.7
Risk-free interest rate		4.8	%		4.8	%		3.7	%
Volatility		28.6	%		31.1	%		35.0	%
Dividend yield		0.7	%		0.7	%		1.0	%
Weighted average fair value per share at grant date	$	24.20		$	26.15		$	14.62

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, 2006		4,296		$	46.35
Granted		690			75.12
Exercised		(1,657	)		40.94
Forfeited		(80	)		53.28
Expired		(78	)		46.79

Outstanding at December 31, 2007		3,171		$	55.25

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 2007, 2006 and 2005 was $72.5 million, $73.6 million and $84.6 million, respectively. The income tax benefit realized from stock options exercised was $18.5 million for the year ended December 31, 2007. The total fair value of options vested in 2007, 2006 and 2005 was $19.6 million, $20.2 million and $20.4 million, respectively. As of December 31, 2007, there was $10.4 million of total unrecognized compensation cost related to nonvested stock options which is expected to be recognized over a weighted average period of 1.9 years.

The following table summarizes information about stock options outstanding as of December 31, 2007 (in thousands, except per option prices and remaining life):


				Outstanding						Exercisable
						Weighted						Weighted
						Average		Weighted				Average		Weighted
						Remaining		Average				Remaining		Average
						Contractual		Exercise				Contractual		Exercise
				Number of		Life		Price Per		Number of		Life		Price Per
Range of Exercise Prices				Options		(In years)		Option		Options		(In years)		Option

$14.49	—	$	21.00		60		1.1	$	20.24		60		1.1	$	20.24
22.88	—		33.50		405		4.3		29.64		405		4.6		29.64
35.81	—		43.39		989		6.1		40.14		821		6.2		39.64
56.21	—		82.28		1,717		8.4		71.21		460		8.0		65.67

Total					3,171		7.0	$	55.25		1,746		6.1	$	43.51

The aggregate intrinsic value of stock options outstanding at December 31, 2007 was $86.7 million, of which $68.3 million relates to awards vested and exercisable and $18.4 million relates to awards expected to vest. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of $82.60 of our common stock as of the end of 2007 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

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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, 2006		747		$	56.23		124		$	61.91
Granted		352			68.59		93			68.54
Vested		(243	)		55.25		(49	)		58.74
Forfeited		(61	)		57.20		(12	)		65.76

Nonvested balance at December 31, 2007		795		$	61.93		156		$	66.56

The weighted average grant date fair value per share for RSAs in 2006 and 2005 was $73.97 and $44.28, respectively. The weighted average grant date fair value per share for RSUs in 2006 and 2005 was $74.00 and $42.60, respectively.

The total grant date fair value of RSAs and RSUs vested in 2007 and 2006 was $16.3 million and $10.6 million, respectively. There were no RSAs or RSUs that vested in 2005. As of December 31, 2007, there was $26.2 million and $6.0 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 1.8 years.

Employee Stock Purchase Plan

Our Employee Stock Purchase Plan (“ESPP”) allows eligible employees to elect to contribute on an after-tax basis between 1% and 10% of their annual pay to purchase our common stock; provided, however, an employee may not contribute more than $25,000 annually to the plan pursuant to Internal Revenue Service restrictions. Shares are purchased at a 15% discount of the fair market value of our common stock on January 1 or December 31, whichever is lower. We currently have 14.5 million shares authorized for issuance under the ESPP, and at December 31, 2007, there were 2.9 million shares reserved for future issuance under the ESPP. Compensation expense determined under SFAS 123(R) for the year ended December 31, 2007 was calculated using the Black-Scholes option pricing model with the following assumptions:


	2007			2006			2005
	Actual			Actual			Pro Forma

Expected life (years)		1.0			1.0			1.0
Interest rate		4.9	%		4.4	%		2.7	%
Volatility		30.5	%		28.0	%		26.6	%
Dividend yield		0.7	%		0.9	%		1.1	%
Weighted average fair value per share at grant date	$	10.39		$	7.66		$	10.05

We calculated estimated volatility using historical daily prices based on the expected life of the stock purchase plan. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the ESPP shares were granted. The dividend yield is based on our history of dividend payouts.

NOTE 5. SALE OF INTEREST AND INVESTMENTS IN AFFILIATES

We have investments in affiliates that are accounted for using the equity method of accounting. The most significant of these affiliates was our 30% interest in WesternGeco, a seismic venture jointly owned with Schlumberger Limited (“Schlumberger”). On April 28, 2006, we sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in cash. We recorded a pre-tax gain of $1,743.5 million ($1,035.2 million, after-tax). Prior to our sale, during 2006 and 2005, we received distributions of $59.6 million and $30.0 million, respectively, from WesternGeco, which were recorded as reductions in the carrying value of our investment.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

In November 2000, we entered into an agreement with WesternGeco, whereby WesternGeco subleases a facility from us for a period of ten years at then current market rates. In 2006, we entered into an extension of the sublease for five additional years with rent to be determined based on market rates in 2010. During 2007, 2006 and 2005, we received payments of $8.2 million, $5.6 million and $6.5 million, respectively, from WesternGeco related to this lease.

The following table includes summarized unaudited combined financial information for the affiliates in which we account for our interests using the equity method of accounting. Included in the table for 2006 are the operating and financial position results for WesternGeco through March 31, 2006, the most recent date for which information is available. All other information for affiliates is as of December 31.


	2007		2006		2005

Combined operating results:
Revenues	$	13.8	$	582.9	$	1,700.7
Operating income		5.1		166.1		327.3
Net income		4.3		145.2		279.7


	2007		2006

Combined financial position:
Current assets	$	11.4	$	1,229.4
Noncurrent assets		11.8		1,116.1

Total assets	$	23.2	$	2,345.5


Current liabilities	$	6.8	$	546.0
Noncurrent liabilities		—		89.1
Stockholders’ equity		16.4		1,710.4

Total liabilities and stockholders’ equity	$	23.2	$	2,345.5

As of December 31, 2007 and 2006, the excess of our investments as recorded on our balance sheet over our pro-rata share of the shareholders’ equity as reported by the affiliates was $4.7 million and $8.4 million, respectively.

NOTE 6. INCOME TAXES

The provision for income taxes on income from continuing operations is comprised of the following for the years ended December 31:


	2007			2006		2005

Current:
United States	$	365.8		$	861.5	$	146.3
Foreign		380.7			371.1		251.1

Total current		746.5			1,232.6		397.4

Deferred:
United States		19.0			97.9		7.0
Foreign		(22.7	)		7.7		0.4

Total deferred		(3.7	)		105.6		7.4

Provision for income taxes	$	742.8		$	1,338.2	$	404.8

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The geographic sources of income from continuing operations before income taxes are as follows for the years ended December 31:


	2007		2006		2005

United States	$	876.5	$	1,917.3	$	409.6
Foreign		1,380.2		1,819.5		869.6

Income from continuing operations before income taxes	$	2,256.7	$	3,736.8	$	1,279.2

Tax benefits of $17.1 million, $19.4 million and $19.8 million associated with the exercise of employee stock options were allocated to equity and recorded in capital in excess of par value in the years ended December 31, 2007, 2006 and 2005, respectively.

The provision for income taxes differs from the amount computed by applying the U.S. statutory income tax rate to income from continuing operations before income taxes for the reasons set forth below for the years ended December 31:


	2007			2006			2005

Statutory income tax at 35%	$	789.9		$	1,307.9		$	447.7
Effect of sale of interest in affiliate		—			98.1			—
Effect of foreign operations		(84.0	)		(86.9	)		(46.0	)
Net tax (benefit) charge related to foreign losses		(0.8	)		(2.7	)		5.5
State income taxes – net of U.S. tax benefit		17.9			12.1			8.8
Cumulative tax effect of SRP		—			—			(10.6	)
Other – net		19.8			9.7			(0.6	)

Provision for income taxes	$	742.8		$	1,338.2		$	404.8

During 2006, we provided $708.3 million for taxes related to the sale of our interest in WesternGeco. Approximately $98.1 million of this tax provision is in excess of the U.S. statutory income tax rate due to taxes provided on the expected repatriation of the non-U.S. proceeds received in the transaction and a larger U.S. tax gain due to lower tax basis compared to book basis.

In 2005, we recognized a $10.6 million deferred tax asset attributable to the cumulative temporary difference between the carrying values of our Supplemental Retirement Plan (“SRP”) for financial reporting and income tax purposes, which had the effect of reducing tax expense.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, as well as operating loss and tax credit carryforwards. The tax effects of our temporary differences and carryforwards are as follows at December 31:


	2007			2006

Deferred tax assets:
Receivables	$	6.3		$	9.9
Inventory		160.5			138.3
Property		49.7			53.3
Employee benefits		28.6			63.4
Other accrued expenses		45.2			46.9
Operating loss carryforwards		43.5			41.1
Tax credit carryforwards		31.3			20.7
Capitalized research and development costs		27.6			39.2
Other		38.8			29.6

Subtotal		431.5			442.4
Valuation allowances		(66.8	)		(50.7	)

Total		364.7			391.7


Deferred tax liabilities:
Goodwill		133.0			130.8
Undistributed earnings of foreign subsidiaries		98.9			150.3
Other		48.4			30.4

Total		280.3			311.5

Net deferred tax asset	$	84.4		$	80.2

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions. We have provided a valuation allowance for operating loss carryforwards in certain non-U.S. jurisdictions where our operations have decreased, currently ceased or we have withdrawn entirely.

We have provided for U.S. and additional foreign taxes for the anticipated repatriation of certain earnings of our foreign subsidiaries. We consider the undistributed earnings of our foreign subsidiaries above the amount 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 $1.6 billion, $0.8 billion and $0.4 billion as of December 31, 2007, 2006 and 2005, 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, 2007, we had approximately $28.5 million of foreign tax credits which may be carried forward indefinitely under applicable foreign law and $2.8 million of state tax credits expiring in varying amounts between 2016 and 2021. The operating loss carryforwards without a valuation allowance will expire in varying amounts over the next twenty years.

In June 2006, the FASB issued FIN 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. FIN 48 addresses the determination of whether tax benefits (e.g. tax deductions or credits) claimed or expected to be claimed on a tax return should be recorded in the financial statements as a reduction to income tax expense and related income tax liabilities. Under FIN 48, the tax benefit from an uncertain tax position is to be recognized as a reduction to income tax expense when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities including resolution of any related appeals or litigation processes. Additionally, the amount of the tax benefit to be recognized is the largest amount of tax benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the taxing authorities. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We adopted FIN 48 on January 1, 2007, pursuant to which we recognized a $78.5 million increase in the gross liability for unrecognized tax benefits which included $17.3 million of interest and penalties. As a result of the implementation of FIN 48, we recognized the following adjustments to our accounts as of January 1, 2007.


	Increase
	(Decrease)

Beginning retained earnings	$	(64.2	)
Deferred tax assets		(0.6	)
Non-current tax receivables		14.9
Tax liabilities		78.5

As of January 1, 2007, we had $422.8 million of tax liabilities for gross unrecognized tax benefits, which includes liabilities for interest and penalties of $50.4 million and $18.1 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 $339.2 million. The remaining approximately $83.6 million, which is recorded as a deferred tax asset, represents tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on all uncertain tax positions.

As of December 31, 2007, we had $456.9 million of tax liabilities for gross unrecognized tax benefits, which includes liabilities for interest and penalties of $71.4 million and $22.1 million, respectively. Our gross unrecognized tax benefits include $9.3 million of additional taxes and related interest and penalties, recorded in 2007, that are associated with disallowed tax deductions taken in previous years, arising from the resolution of investigations with the Securities and Exchange Commission (“SEC”) and the Department of Justice (“DOJ”). If we were to prevail on all uncertain tax positions, the net effect would be a benefit to our effective tax rate of approximately $373.3 million. The remaining approximately $83.6 million, which is recorded as a deferred tax asset, represents tax benefits that would be received in different taxing jurisdictions in the event that we did not prevail on all uncertain tax positions.

We have elected under FIN 48 to continue with our prior policy to classify interest and penalties related to unrecognized tax benefits as income taxes in our financial statements. For the year ended December 31, 2007, we recognized $25.0 million of interest and penalties expense 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	$	354.3		$	68.5		$	422.8
Increase in prior year tax positions		2.8			21.1			23.9
Increase in current year tax positions		20.1			5.3			25.4
Decrease related to settlements with taxing authorities and lapse of statute of limitations		(21.6	)		(5.5	)		(27.1	)
Increase due to effects of foreign currency translation		7.8			4.1			11.9

Balance at December 31, 2007	$	363.4		$	93.5		$	456.9

It is expected that the amount of unrecognized tax benefits will change in the next twelve months due to expiring statutes, audit activity, tax payments, competent authority proceedings related to transfer pricing, or final decisions in matters that are the subject of litigation in various taxing jurisdictions in which we operate. At December 31, 2007, current taxes payable included approximately $105.5 million of gross unrecognized tax benefits, which we expect to settle within the next twelve months primarily as the result of audit settlements or statute expirations in several taxing jurisdictions. The most significant uncertainties are due to possible transfer pricing adjustments related to goods and services provided across borders in various countries.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

At December 31, 2007, approximately $351.4 million of gross unrecognized tax benefits were included in the non-current portion of our income tax liabilities, for which the settlement period cannot be determined; however, it is not expected to be within the next twelve months.

We operate in over 90 countries and are subject to income taxes in most taxing jurisdictions in which we operate. The following table summarizes the earliest tax years that remain subject to examination by the major taxing jurisdictions in which we operate. These jurisdictions are those we project to have the highest tax liability for 2007.


	Earliest Open Tax			Earliest Open Tax
Jurisdiction	Period		Jurisdiction	Period

Argentina		2002	Norway		1999
Canada		1998	Russia		2005
Germany		2003	Saudi Arabia		1995
Italy		1999	United Kingdom		2003
Netherlands		1998	United States		2002

NOTE 7. EARNINGS PER SHARE

A reconciliation of the number of shares used for the basic and diluted EPS computations is as follows for the years ended December 31:


	2007		2006		2005

Weighted average common shares outstanding for basic EPS		318.0		330.6		339.4
Effect of dilutive securities – stock plans		2.1		2.0		2.1

Adjusted weighted average common shares outstanding for diluted EPS		320.1		332.6		341.5


Future potentially dilutive shares excluded from diluted EPS:
Options with an exercise price greater than the average market price for the period		0.6		0.7		0.7

NOTE 8. INVENTORIES

Inventories are comprised of the following at December 31:


	2007		2006

Finished goods	$	1,414.0	$	1,239.5
Work in process		177.5		188.0
Raw materials		122.9		101.3

Total	$	1,714.4	$	1,528.8

NOTE 9. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are comprised of the following at December 31:


	Depreciation
	Period	2007			2006

Land		$	62.0		$	46.1
Buildings and improvements	2 - 40 years		774.7			661.0
Machinery and equipment	2 - 20 years		2,745.0			2,387.6
Rental tools and equipment	1 - 10 years		1,739.3			1,419.2

Subtotal			5,321.0			4,513.9
Accumulated depreciation			(2,976.4	)		(2,713.4	)

Total		$	2,344.6		$	1,800.5

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 10. GOODWILL AND INTANGIBLE ASSETS

The changes in the carrying amount of goodwill are detailed below by segment:


	Drilling			Completion
	and Evaluation			and Production			Total

Balance as of December 31, 2005	$	904.1		$	411.7		$	1,315.8
Goodwill from acquisitions during the period		5.3			30.4			35.7
Adjustments for final purchase price allocations of previous acquisitions		—			(5.0	)		(5.0	)
Translation adjustments and other		(0.2	)		0.7			0.5

Balance as of December 31, 2006		909.2			437.8			1,347.0
Adjustments for final purchase price allocations of previous acquisitions		2.0			1.5			3.5
Translation adjustments and other		2.8			0.9			3.7

Balance as of December 31, 2007	$	914.0		$	440.2		$	1,354.2

We perform an annual impairment test of goodwill as of October 1 of every year. There were no impairments of goodwill in 2007, 2006 or 2005 related to the annual impairment test.

Intangible assets are comprised of the following at December 31:


	2007							2006
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net

Technology–based	$	240.6	$	(105.1	)	$	135.5	$	236.7	$	(87.2	)	$	149.5
Contract–based		15.1		(9.2	)		5.9		13.8		(6.6	)		7.2
Marketing–related		5.7		(5.7	)		—		5.7		(5.7	)		—
Customer–based		13.6		(3.8	)		9.8		13.7		(2.4	)		11.3
Other		0.3		(0.3	)		—		0.7		(0.4	)		0.3

Total amortizable intangible assets		275.3		(124.1	)		151.2		270.6		(102.3	)		168.3
Marketing–related intangible assets with indefinite useful lives		25.4		—			25.4		22.1		—			22.1

Total	$	300.7	$	(124.1	)	$	176.6	$	292.7	$	(102.3	)	$	190.4

Intangible assets are amortized either on a straight-line basis with estimated useful lives ranging from 1 to 20 years, or on a basis that reflects the pattern in which the economic benefits of the intangible assets are expected to be realized, which range from 15 to 30 years.

Amortization expense included in net income for the years ended December 31, 2007, 2006 and 2005 was $20.8 million, $20.0 million and $15.2 million, respectively. Estimated amortization expense for each of the subsequent five fiscal years is expected to be as follows: 2008 – $19.1 million; 2009 – $18.3 million; 2010 – $14.8 million; 2011 – $13.8 million and 2012 – $13.5 million.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 11. INDEBTEDNESS

Total debt consisted of the following at December 31:


	2007		2006

6.25% Notes due January 2009 with an effective interest rate of 4.72%, net of unamortized discount and debt issuance costs of $0.3 at December 31, 2007 ($0.7 at December 31, 2006)	$	330.0	$	334.8

6.00% Notes due February 2009 with an effective interest rate of 6.11%, net of unamortized discount and debt issuance costs of $0.2 at December 31, 2007 ($0.4 at December 31, 2006)		199.8		199.6

8.55% Debentures due June 2024 with an effective interest rate of 8.76%, net of unamortized discount and debt issuance costs of $2.3 at December 31, 2007 ($2.4 at December 31, 2006)		147.7		147.6

6.875% Notes due January 2029 with an effective interest rate of 7.08%, net of unamortized discount and debt issuance costs of $8.1 at December 31, 2007 ($8.3 at December 31, 2006)		391.9		391.7

Other debt		15.4		1.4

Total debt		1,084.8		1,075.1
Less short-term debt and current maturities		15.4		1.3

Long-term debt	$	1,069.4	$	1,073.8

In prior years, we terminated various interest rate swap agreements prior to their scheduled maturities resulting in net gains. The net gains were deferred and are being amortized as a net reduction of interest expense over the remaining life of the underlying debt securities. The unamortized net deferred gains of $5.3 million and $10.5 million are included in the 6.25% Notes due January 2009 and reported in long-term debt in the consolidated balance sheets at December 31, 2007 and 2006, respectively.

Maturities of debt at December 31, 2007 are as follows: 2008 – $15.4 million; 2009 – $529.8 million; 2010 – $0.0 million; 2011 – $0.0 million, 2012 – $0.0 million; and $539.6 million thereafter.

NOTE 12. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

Our financial instruments include cash and short-term investments, noncurrent investments in auction rate securities, accounts receivable, accounts payable, debt, foreign currency forward contracts and foreign currency option contracts. Except as described below, the estimated fair value of such financial instruments at December 31, 2007 and 2006 approximates their carrying value as reflected in our consolidated balance sheets. The fair value of our debt and foreign currency forward contracts has been estimated based on quoted year end market prices.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The estimated fair value of total debt at December 31, 2007 and 2006 was $1,169.7 million and $1,171.0 million, respectively, which differs from the carrying amounts of $1,084.8 million and $1,075.1 million, respectively, included in our consolidated balance sheets.

Foreign Currency Forward Contracts

Concentration of Credit Risk

We sell our products and services to numerous companies in the oil and natural gas industry. Although this concentration could affect our overall exposure to credit risk, we believe that we are exposed to minimal risk since the majority of our business is conducted with major companies within the industry. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral for our accounts receivable. In some cases, we will require payment in advance or security in the form of a letter of credit or bank guarantee.

We maintain cash deposits with major banks that may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that the risk of any loss is minimal.

NOTE 13. SEGMENT AND RELATED INFORMATION

We are a provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We report results for our product-line focused divisions under two segments: the Drilling and Evaluation segment and the Completion and Production segment. We have aggregated the divisions within each segment because they have similar economic characteristics and because the long-term financial performance of these divisions is affected by similar economic conditions. They also operate in the same markets, which includes all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance. The WesternGeco segment consisted of our 30% interest in WesternGeco, which we sold in April 2006. The accounting policies of our segments are the same as those described in Note 1 of Notes to Consolidated Financial Statements.

•

The Drilling and Evaluation segment consists of the Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits), INTEQ (drilling, measurement-while-drilling and logging-while-drilling) and Baker Atlas (wireline

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

			formation evaluation and wireline completion services) divisions. The Drilling and Evaluation segment provides products and services used to drill and evaluate oil and natural gas wells.

	•		The Completion and Production segment consists of the Baker Oil Tools (workover, fishing and completion equipment), Baker Petrolite (oilfield specialty chemicals) and Centrilift (electrical submersible pumps and progressing cavity pumps) divisions and the ProductionQuest (production optimization and permanent monitoring) business unit. The Completion and Production segment provides equipment and services used from the completion phase through the productive life of oil and natural gas wells.

The performance of our segments is evaluated based on segment profit (loss), which is defined as income from continuing operations before income taxes, interest expense, interest and dividend income and accounting changes. The “Corporate and Other” column includes corporate-related items, the pre-tax gain on the sale of our interest in WesternGeco of $1,743.5 million, the financial charge of $46.1 million recorded in connection with the settlement negotiations with the SEC and DOJ, results of insignificant operations and, as it relates to segment profit (loss), income and expense not allocated to the segments. During the fourth quarter of 2007, we started allocating certain expenses previously reported in “Corporate and Other”, to the Drilling and Evaluation and Completion and Production segments. These expenses consist of administrative operations support costs that are more closely related to operating activities. The impact of this allocation was a reduction to “Corporate and Other” of $15.4 million, $12.2 million and $33.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. All prior periods have been reclassified to conform to this new presentation.

The “Corporate and Other” column also includes assets of discontinued operations as of December 31, 2005. Summarized financial information is shown in the following table.


	Drilling
	and		Completion and					Total
	Evaluation		Production			WesternGeco		Oilfield		Corporate and Other			Total

2007
Revenues	$	5,293.2	$	5,135.0		$	—	$	10,428.2	$	—		$	10,428.2
Equity in income (loss) of affiliates		1.5		(0.4	)		—		1.1		0.1			1.2
Segment profit (loss)		1,396.2		1,112.2			—		2,508.4		(251.7	)		2,256.7
Total assets		4,720.4		4,095.9			—		8,816.3		1,040.3			9,856.6
Investment in affiliates		8.8		—			—		8.8		—			8.8
Capital expenditures		773.3		352.3			—		1,125.6		1.4			1,127.0
Depreciation and amortization		335.0		162.5			—		497.5		23.7			521.2

2006
Revenues	$	4,660.8	$	4,366.6		$	—	$	9,027.4	$	—		$	9,027.4
Equity in income of affiliates		1.3		0.4			58.7		60.4		—			60.4
Segment profit (loss)		1,241.8		941.9			58.7		2,242.4		1,494.4			3,736.8
Total assets		3,988.8		3,595.7			—		7,584.5		1,121.2			8,705.7
Investment in affiliates		7.3		12.7			—		20.0		—			20.0
Capital expenditures		631.8		279.7			—		911.5		10.7			922.2
Depreciation and amortization		274.5		134.8			—		409.3		24.4			433.7

2005
Revenues	$	3,694.2	$	3,490.0		$	—	$	7,184.2	$	1.3		$	7,185.5
Equity in income of affiliates		1.1		2.2			96.7		100.0		0.1			100.1
Segment profit (loss)		749.6		666.0			96.7		1,512.3		(233.1	)		1,279.2
Total assets		3,221.9		2,882.6			688.0		6,792.5		1,014.9			7,807.4
Investment in affiliates		6.1		12.2			660.6		678.9		—			678.9
Capital expenditures		347.8		129.6			—		477.4		0.9			478.3
Depreciation and amortization		232.7		121.1			—		353.8		28.6			382.4

For the years ended December 31, 2007, 2006 and 2005, there were no revenues attributable to one customer that accounted for more than 10% of total revenues.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

The following table presents the details of “Corporate and Other” segment profit (loss) for the years ended December 31:


	2007			2006			2005

Corporate and other expenses	$	(229.4	)	$	(247.7	)	$	(178.8	)
Interest expense		(66.1	)		(68.9	)		(72.3	)
Interest and dividend income		43.8			67.5			18.0
Gain on sale of interest in affiliate		—			1,743.5			—

Total	$	(251.7	)	$	1,494.4		$	(233.1	)

The following table presents the details of “Corporate and Other” total assets at December 31:


	2007		2006		2005

Cash and other assets	$	795.0	$	902.8	$	771.8
Accounts receivable		7.0		8.8		9.3
Current deferred tax asset		1.3		2.6		29.4
Property, plant and equipment		37.5		65.8		78.5
Other tangible assets		199.5		141.2		109.3
Assets of discontinued operations		—		—		16.6

Total	$	1,040.3	$	1,121.2	$	1,014.9

The following table presents consolidated revenues by country based on the location of the use of the products or services for the years ended December 31:


	2007		2006		2005

United States	$	3,803.1	$	3,392.5	$	2,576.1
United Kingdom		602.6		514.8		402.9
Canada		554.9		607.1		472.8
Norway		518.2		438.4		376.1
Saudi Arabia		481.4		391.3		170.6
Russia		428.5		237.6		168.6
Brazil		219.4		133.0		98.4
Other countries		3,820.1		3,312.7		2,920.0

Total	$	10,428.2	$	9,027.4	$	7,185.5

The following table presents net property, plant and equipment by country based on the location of the asset at December 31:


	2007		2006		2005

United States	$	1,127.6	$	927.8	$	734.4
United Kingdom		226.5		188.8		133.2
Germany		85.0		51.7		49.4
Canada		84.9		78.8		67.9
Norway		66.6		50.7		43.8
Brazil		64.5		34.3		21.0
Russia		58.5		24.8		13.5
Other countries		631.0		443.6		292.3

Total	$	2,344.6	$	1,800.5	$	1,355.5

NOTE 14. EMPLOYEE BENEFIT PLANS

DEFINED BENEFIT PLANS

We have noncontributory defined benefit pension plans (“Pension Benefits”) covering employees primarily in the U.S., the U.K. and Germany. In the U.S., we merged two pension plans effective January 1, 2007, resulting in one tax-qualified U.S. pension plan, the Baker Hughes Incorporated Pension Plan (“BHIPP”). Under the provisions of BHIPP, a hypothetical cash balance account is established for each participant. Such accounts receive pay credits on a quarterly basis. The quarterly pay credit is based on a

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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 BHIPP also includes frozen accrued benefits for participants in legacy defined benefit plans. For the majority of the participants in the U.K. pension plans, we do not accrue benefits as the plans are frozen; however, there are a limited number of members who still accrue future benefits on a defined benefit basis. The Germany pension plan is an unfunded plan where benefits are based on creditable years of service, creditable pay and accrual rates. We also provide certain postretirement health care benefits (“other postretirement benefits”), through an unfunded plan, to substantially all U.S. employees who retire and have met certain age and service requirements.

We adopted SFAS 158 effective December 31, 2006. SFAS 158 requires an employer to recognize the overfunded or underfunded status of its defined pension and postretirement benefit plans as a net asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. Additionally, SFAS 158 requires an employer to measure the funded status of each of its plans as of the date of its year end statement of financial position. We will adopt this provision on December 31, 2008, as allowed under SFAS 158, using the Alternative Method to transition to a fiscal year-end measurement date. The funded status of all our pension and other postretirement benefit plans are currently measured as of October 1 of each year presented.

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”).


	U.S. Pension Benefits						Non-U.S. Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006			2007			2006

Change in benefit obligation:
Benefit obligation at beginning of year	$	269.6		$	238.8		$	360.5		$	287.5		$	156.9		$	184.5
Service cost		31.6			26.2			3.0			3.4			7.5			7.4
Interest cost		15.7			12.8			18.3			15.0			9.0			9.7
Actuarial (gain) loss		(19.7	)		(0.1	)		(58.0	)		24.6			(4.1	)		(31.8	)
Benefits paid		(12.6	)		(11.7	)		(16.4	)		(10.6	)		(13.5	)		(12.9	)
Plan amendments		(1.2	)		6.1			—			—			—			—
Other		(3.1	)		(2.5	)		1.4			0.1			—			—
Exchange rate adjustments		—			—			9.9			40.5			—			—

Benefit obligation at end of year		280.3			269.6			318.7			360.5			155.8			156.9


Change in plan assets:
Fair value of plan assets at beginning of year		410.2			354.1			273.3			207.6			—			—
Actual return on plan assets		62.4			39.7			9.9			23.3			—			—
Employer contributions		2.4			30.6			33.9			22.3			13.5			12.9
Benefits paid		(12.6	)		(11.7	)		(16.4	)		(10.6	)		(13.5	)		(12.9	)
Other		(3.1	)		(2.5	)		—			0.1			—			—
Exchange rate adjustments		—			—			5.5			30.6			—			—

Fair value of plan assets at end of year		459.3			410.2			306.2			273.3			—			—


Funded status over (under) at measurement date		179.0			140.6			(12.5	)		(87.2	)		(155.8	)		(156.9	)
Employer contributions – fourth quarter		0.5			0.6			3.5			18.3			3.7			3.8

Funded status over (under) at end of year	$	179.5		$	141.2		$	(9.0	)	$	(68.9	)	$	(152.1	)	$	(153.1	)

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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
	2007			2006			2007			2006			2007			2006

Noncurrent assets	$	197.0		$	160.1		$	30.6		$	—		$	—		$	—
Current liabilities		(2.3	)		(2.3	)		(0.5	)		(0.6	)		(13.9	)		(13.8	)
Noncurrent liabilities		(15.2	)		(16.6	)		(39.1	)		(68.3	)		(138.2	)		(139.3	)

Net amount recognized	$	179.5		$	141.2		$	(9.0	)	$	(68.9	)	$	(152.1	)	$	(153.1	)

The weighted average asset allocations by asset category for the plans are as follows at December 31:


	Percentage of Plan Assets
	U.S. Pension Benefits									Non-U.S. Pension Benefits
Asset Category	Target			2007			2006			Target			2007			2006

Equity securities		68	%		72	%		68	%		54	%		55	%		55	%
Debt securities		25	%		22	%		24	%		30	%		28	%		28	%
Real estate		7	%		6	%		8	%		13	%		12	%		12	%
Other		—			—			—			3	%		5	%		5	%

Total		100	%		100	%		100	%		100	%		100	%		100	%

We have investment committees that meet at least quarterly to review the portfolio returns and periodically to determine asset-mix targets based on asset/liability studies. Third-party investment consultants assisted us in developing asset allocation strategies to determine our expected rates of return and expected risk for various investment portfolios. The investment committees considered these studies in the formal establishment of the current asset-mix targets based on the projected risk and return levels for all major asset classes.

The accumulated benefit obligation (“ABO”) is the actuarial present value of pension benefits attributed to employee service to date and present compensation levels. The ABO differs from the PBO in that the ABO does not include any assumptions about future compensation levels. The ABO for all U.S. plans was $275.2 million and $260.9 million at December 31, 2007 and 2006, respectively. The ABO for all non-U.S. plans was $309.0 million and $353.3 million at December 31, 2007 and 2006, 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
	2007		2006		2007		2006		2007		2006

Projected benefit obligation	$	18.1	$	19.5	$	41.9	$	355.1		n/a		n/a
Accumulated benefit obligation		18.0		19.2		34.3		348.4	$	155.8	$	156.9
Fair value of plan assets		—		—		2.0		268.1		n/a		n/a

Weighted average assumptions used to determine benefit obligations for these plans are as follows for the years ended December 31:


													Other Postretirement
	U.S. Pension Benefits						Non-U.S. Pension Benefits						Benefits
	2007			2006			2007			2006			2007			2006

Discount rate		6.3	%		6.0	%		5.7	%		5.0	%		6.3	%		6.0	%
Rate of compensation increase		4.0	%		4.0	%		4.1	%		3.9	%		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.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

Accumulated Other Comprehensive Loss

The amounts recognized in accumulated other comprehensive loss consist of the following as of December 31:


										Other
	U.S. Pension Benefits					Non-U.S. Pension Benefits				Postretirement Benefits
	2007			2006		2007		2006		2007		2006

Net loss (gain)	$	(9.5	)	$	38.8	$	74.7	$	123.4	$	7.3	$	11.5
Net prior service cost (credit)		4.6			6.4		0.2		0.2		5.4		6.4
Net transition obligation		—			—		0.1		0.1		—		—

Total	$	(4.9	)	$	45.2	$	75.0	$	123.7	$	12.7	$	17.9

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year are $1.9 million and $0.5 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 $1.1 million.

Net Periodic Benefit Costs

The components of net periodic benefit cost are as follows for the years ended December 31:


																			Other
	U.S. Pension Benefits									Non-U.S. Pension Benefits									Postretirement Benefits
	2007			2006			2005			2007			2006			2005			2007		2006		2005

Service cost	$	31.6		$	26.2		$	22.8		$	3.0		$	3.4		$	2.2		$	7.5	$	7.4	$	6.1
Interest cost		15.7			12.8			11.9			18.3			15.0			13.8			9.0		9.7		9.7
Expected return on plan assets		(34.3	)		(31.6	)		(25.9	)		(19.5	)		(16.0	)		(13.2	)		—		—		—
Amortization of prior service cost		0.6			0.1			—			—			—			—			1.0		0.8		0.6
Amortization of net loss		0.6			0.8			2.6			2.9			2.6			2.6			—		2.1		2.0
Special termination benefit cost		—			—			0.7			—			—			—			—		—		—
Settlement/curtailments loss		—			—			—			—			—			0.2			—		—		—

Net periodic benefit cost	$	14.2		$	8.3		$	12.1		$	4.7		$	5.0		$	5.6		$	17.5	$	20.0	$	18.4

Weighted average assumptions used to determine net periodic benefit costs for these plans are as follows for the years ended December 31:


																			Other
	U.S. Pension Benefits									Non-U.S. Pension Benefits									Postretirement Benefits
	2007			2006			2005			2007			2006			2005			2007			2006			2005

Discount rate		6.0	%		5.5	%		6.0	%		5.0	%		4.9	%		5.7	%		6.0	%		5.5	%		6.0	%
Expected rate of return on plan assets		8.5	%		8.5	%		8.5	%		6.9	%		6.9	%		7.4	%		n/a			n/a			n/a

Rate of compensation increase		4.0	%		4.0	%		3.5	%		3.9	%		3.5	%		3.5	%		n/a			n/a			n/a

In selecting the expected rate of return on plan assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for the benefits of these plans. This includes considering the trusts’ asset allocation and the expected returns likely to be earned over the life of the plans.

Expected Cash Flows

For all pension plans, we make annual contributions to the plans in amounts equal to or greater than amounts necessary to meet minimum governmental funding requirements. As a result of the merger of our U.S. plans effective January 1, 2007, BHIPP is overfunded; therefore, we are not required nor do we intend to make pension contributions to BHIPP in 2008, and we currently estimate that we will not be required to make contributions to BHIPP for four to seven years thereafter. In 2008, we expect to contribute between $2.0 million and $3.0 million to our nonqualified U.S. pension plans and between $13.0 million and $15.0 million to the non-U.S. pension plans.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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 $2.2 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

2008	$	15.9	$	12.7	$	14.3
2009		17.0		12.6		15.0
2010		18.9		10.6		15.3
2011		21.4		10.0		15.9
2012		25.2		8.8		16.7
2013-2017		175.9		37.3		95.5

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, 2007, the health care cost trend rate was 8.5% for employees under age 65 and 6.5% 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 2012. A one percentage point change in assumed health care cost trend rates would have had the following effects on 2007:


	One Percentage		One Percentage
	Point Increase		Point Decrease

Effect on total of service and interest cost components	$	0.5	$	(0.4	)
Effect on postretirement welfare benefit obligation		6.4		(5.8	)

DEFINED CONTRIBUTION PLANS

During the periods reported, generally all of our U.S. employees were eligible to participate in our sponsored Thrift Plan, which is a 401(k) plan under the Internal Revenue Code of 1986, as amended (“the Code”). The Thrift Plan allows eligible employees to elect to contribute from 1% to 50% of their salaries to an investment trust. Beginning January 1, 2007, employee contributions are matched by the Company in cash at the rate of $1.00 per $1.00 employee contribution for the first 5% of the employee’s salary. In prior years, employee contributions were matched in cash by us at the rate of $1.00 per $1.00 employee contribution for the first 3% and $0.50 per $1.00 employee contribution for the next 2% of the employee’s salary. In all years, such contributions vest immediately. In addition, we make cash contributions for all eligible employees between 2% and 5% of their salary depending on the 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. Our contributions to the Thrift Plan and several other non-U.S. defined contribution plans amounted to $130.7 million, $102.2 million and $86.5 million in 2007, 2006 and 2005, 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 $11.0 million, $8.3 million and $7.2 million for 2007, 2006 and 2005, respectively.

In 2008, we expect to contribute between $142.0 million and $153.0 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, 2007 and 2006 was $14.4 million and $17.6 million, respectively, and is included in other liabilities in our consolidated balance sheet.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 15. COMMITMENTS AND CONTINGENCIES

Leases

At December 31, 2007, 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, 2012 are $95.0 million, $64.9 million, $43.2 million, $29.5 million and $21.7 million, respectively, and $123.0 million in the aggregate thereafter. We have not entered into any significant capital leases during the three years ended December 31, 2007.

Litigation

On March 29, 2002, we announced that we had been advised that the SEC and the DOJ were conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC issued a formal order of investigation into possible violations of provisions under the Foreign Corrupt Practices Act (“FCPA”) regarding antibribery, books and records and internal controls. In connection with the investigations, the SEC issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We provided documents to and cooperated fully with the SEC and DOJ. In addition, we conducted internal investigations into these matters. Our internal investigations identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Angola, Kazakhstan and Nigeria, as well as potential liabilities to government authorities in Nigeria. Evidence obtained during the course of the investigations was provided to the SEC and DOJ.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

and-records and internal-controls provisions related to our operations in Nigeria, Angola, Kazakhstan, Indonesia, Russia, and Uzbekistan, and the SEC’s cease and desist order of September 12, 2001. The SEC Order became effective on May 1, 2007, which is the date it was confirmed by the Court. The SEC order enjoins us from violating the FCPA’s antibribery, books-and-records, and internal-controls provisions. As in the DPA, it requires that we retain the independent monitor to assess our FCPA compliance policies and procedures for the three-year period.

Under the terms of the settlements with the DOJ and the SEC, the Company and BHSII paid in the second quarter of 2007, $44.1 million ($11 million in criminal penalties, $10 million in civil penalties, $19.9 million in disgorgement of profits and $3.2 million in pre-judgment interest) to settle these investigations. In the fourth quarter of 2006, we recorded a financial charge for the potential settlement.

We have retained, and the SEC and DOJ have approved, an independent monitor to assess our FCPA compliance policies and procedures for the specified three-year period.

On May 4, 2007 and May 15, 2007, The Sheetmetal Workers’ National Pension Fund and Chris Larson, respectively, instituted shareholder derivative lawsuits for and on the Company’s behalf against certain current and former members of the Board of Directors and certain 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 officers, and the Company as a nominal defendant. The complaints in all three 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. The lawsuits brought by the Sheetmetal Workers’ National Pension Fund and The Alaska Plumbing and Pipefitting Industry Pension Trust are pending in the Houston Division of the United States District Court for the Southern District of Texas. These lawsuits have been consolidated and an amended complaint in the consolidated action was filed on October 15, 2007. The lawsuit brought by Chris Larson is pending in the 215th District Court of Harris County, Texas. We do not expect these lawsuits to have a material adverse effect on our consolidated financial statements.

Further information is contained in the “Environmental Matters” section of Item 1. Business and Item 3. Legal Proceedings both contained herein.

Environmental Matters

Our past and present operations include activities which are subject to extensive domestic (including U.S. federal, state and local) and international environmental regulations with regard to air, land and water quality and other environmental matters. Our environmental procedures, policies and practices are designed to ensure compliance with existing laws and regulations and to minimize the possibility of significant environmental damage.

We are involved in voluntary remediation projects at some of our present and former manufacturing locations or other facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency-issued consent decree or agreed order. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. Remediation cost estimates include direct costs related to the environmental investigation, external consulting activities, governmental oversight fees, treatment equipment and costs associated with long-term operation, maintenance and monitoring of a remediation project.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

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 $16.9 million and $17.3 million, which includes accruals of $5.3 million and $5.9 million for the various Superfund sites, at December 31, 2007 and 2006, 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

NOTE 16. OTHER SUPPLEMENTAL INFORMATION

Product Warranty Liability

The changes in the aggregate product warranty liability are as follows:



Balance as of December 31, 2005	$	13.4
Claims paid		(6.3	)
Additional warranties		11.4
Revisions in estimates for previously issued warranties		3.0
Other		1.1

Balance as of December 31, 2006		22.6
Claims paid		(10.0	)
Additional warranties		3.7
Revisions in estimates for previously issued warranties		(1.9	)
Other		0.4

Balance as of December 31, 2007	$	14.8

Asset Retirement Obligations

On December 31, 2005, we adopted FASB Interpretation No. 47,Conditional Asset Retirement Obligations(“FIN 47”). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143,Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with the special handling of asbestos related materials in certain facilities.

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We have certain facilities that contain asbestos related materials for which a liability has not been recognized because we are unable to determine the time frame over which these obligations may be settled. Our normal practice is to conduct asbestos abatement procedures when required by contractual requirements related to asset disposals or when a facility with asbestos is subject to significant renovation or is demolished. We have no plans or expectations to sell, abandon or demolish these other facilities nor do we anticipate the need for major renovations to them resulting from technological or operations changes or other factors. We expect these other facilities to be operational in their current state for the foreseeable future and, therefore, the time frame over which these obligations will be settled cannot be determined. As a result, sufficient information does not exist to enable us to reasonably estimate the fair value of the asset retirement obligation.

The changes in the asset retirement obligation liability are as follows:



Balance as of December 31, 2005	$	17.4
Liabilities incurred		1.3
Liabilities settled		(1.2	)
Accretion expense		0.3
Revisions to existing liabilities		(2.3	)
Translation adjustments		0.2

Balance as of December 31, 2006		15.7
Liabilities incurred		3.2
Liabilities settled		(2.5	)
Accretion expense		0.4
Revisions to existing liabilities		(0.9	)
Translation adjustments		(0.1	)

Balance as of December 31, 2007	$	15.8

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, is comprised of the following at December 31:


	2007			2006

Foreign currency translation adjustments	$	11.9		$	(60.3	)
Pension and other postretirement benefits		(56.1	)		(126.9	)

Total	$	(44.2	)	$	(187.2	)

Other

Supplemental consolidated statement of operations information is as follows for the years ended December 31:


	2007		2006		2005

Rental expense (generally transportation equipment and warehouse facilities)	$	179.4	$	161.0	$	138.7
Research and development		233.5		216.2		188.2

Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

NOTE 17. QUARTERLY DATA (UNAUDITED)


	First		Second		Third		Fourth		Total
	Quarter		Quarter		Quarter		Quarter		Year

2007
Revenues	$	2,472.8	$	2,537.5	$	2,677.6	$	2,740.3	$	10,428.2
Gross profit⁽¹⁾		781.1		773.2		817.6		838.7		3,210.6
Income from continuing operations		555.1		531.8		576.4		593.4		2,256.7
Net income		374.7		349.6		389.1		400.5		1,513.9
Basic earnings per share:
Income from continuing operations		1.17		1.10		1.23		1.27		4.76
Net income		1.17		1.10		1.23		1.27		4.76
Diluted earnings per share:
Income from continuing operations		1.17		1.09		1.22		1.26		4.73
Net income		1.17		1.09		1.22		1.26		4.73
Dividends per share		0.13		0.13		0.13		0.13		0.52
Common stock market prices:
High		71.94		89.36		90.73		98.67
Low		62.74		66.73		75.84		78.23

2006
Revenues	$	2,062.0	$	2,203.3	$	2,309.4	$	2,452.7	$	9,027.4
Gross profit⁽¹⁾		612.1		674.6		739.7		785.7		2,812.1
Income from continuing operations		318.8		1,395.0		358.6		326.2		2,398.6
Net income		339.2		1,395.0		358.6		326.2		2,419.0
Basic earnings per share:
Income from continuing operations		0.93		4.15		1.10		1.02		7.26
Net income		0.99		4.15		1.10		1.02		7.32
Diluted earnings per share:
Income from continuing operations		0.93		4.14		1.09		1.02		7.21
Net income		0.99		4.14		1.09		1.02		7.27
Dividends per share		0.13		0.13		0.13		0.13		0.52
Common stock market prices:
High		77.44		88.60		83.65		78.25
Low		63.93		67.75		62.17		66.06


⁽¹⁾		Represents revenues less cost of sales, cost of services and rentals and research and engineering.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of December 31, 2007, our management, including our principal executive officer and principal financial officer, conducted an evaluation of our disclosure controls and procedures. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures as of December 31, 2007 are effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Design and Evaluation of Internal Control Over Financial Reporting

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2007. 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. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the caption entitled “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” and are incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

The following events occurred subsequent to the period covered by this Form 10-K and are reportable under Form 8-K:

Item 5.02 — Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

Amended and Restated Executive Severance Plan. In order to comply with Section 409A of the Internal Revenue Code of 1986, as amended, and to establish severance benefits for a new salary grade, on February 7, 2008, the Company amended and restated the Baker Hughes Incorporated Executive Severance Plan (the “ESP”). A copy of the ESP is attached hereto as Exhibit 10.17.

Amended and Restated Annual Incentive Compensation Plan. On February 20, 2008, the Company amended and restated the Baker Hughes Incorporated Annual Incentive Compensation Plan (the “ICP”). The amendments were undertaken primarily to clarify the definition of retirement and to adjust the “banking” feature for awards under the ICP. A copy of the ICP is attached hereto as Exhibit 10.18.

The foregoing descriptions of the ESP and ICP do not purport to be complete and are qualified in their entirety by reference to such plans, which are filed with this Form 10-K as Exhibits 10.17 and 10.18, respectively, and incorporated herein by reference.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information regarding the Business Code of Conduct and Code of Ethical Conduct Certificates for our principal executive officer, principal financial officer and principal accounting officer are described in Item 1. Business of this Annual Report. Information concerning our directors is set forth in the sections entitled “Proposal No. 1, Election of Directors,” and “Corporate Governance – Committees of the Board – Audit/Ethics Committee” in our Proxy Statement for the Annual Meeting of Stockholders to be held April 24, 2008 (“Proxy Statement”), which sections are incorporated herein by reference. For information regarding our executive officers, see “Item 1. Business – Executive Officers” in this Annual Report on Form 10-K. Additional information regarding compliance by directors and executive officers with Section 16(a) of the Exchange Act is set forth under the section entitled “Compliance with Section 16(a) of the Securities Exchange Act of 1934” in our Proxy Statement, which section is incorporated herein by reference. For information concerning our Business Code of Conduct and Code of Ethical Conduct Certificates, see “Item 1. Business” in this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Information for this item is set forth in the following sections of our Proxy Statement, which sections are incorporated herein by reference: “Compensation Discussion and Analysis,” “Executive Compensation,” “Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report.”

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information concerning security ownership of certain beneficial owners and our management is set forth in the sections entitled “Voting Securities” and “Security Ownership of Management” in our Proxy Statement, which sections are incorporated herein by reference.

Our Board of Directors has approved procedures for use under our Securities Trading and Disclosure Policy to permit our employees, officers and directors to enter into written trading plans complying with Rule 10b5-1 under the Exchange Act. Rule 10b5-1 provides criteria under which such an individual may establish a prearranged plan to buy or sell a specified number of shares of a company’s stock over a set period of time. Any such plan must be entered into in good faith at a time when the individual is not in possession of material, nonpublic information. If an individual establishes a plan satisfying the requirements of Rule 10b5-1, such individual’s subsequent receipt of material, nonpublic information will not prevent transactions under the plan from being executed. Certain of our officers have advised us that they have and may enter into a stock sales plan for the sale of shares of our common stock which are intended to comply with the requirements of Rule 10b5-1 of the Exchange Act. In addition, the Company has and may in the future enter into repurchases of our common stock under a plan that complies with Rule 10b5-1 or Rule 10b-18 of the Exchange Act.

Equity Compensation Plan Information

The information in the following table is presented as of December 31, 2007 with respect to shares of our common stock that may be issued under our existing equity compensation plans, including the Baker Hughes Incorporated 1993 Stock Option Plan, the Baker Hughes Incorporated Long-Term Incentive Plan and the Baker Hughes Incorporated 2002 Directors & Officers Long-Term Incentive Plan, all of which have been approved by our stockholders.

(In millions of shares)

Number of

Securities

Remaining Available

Number of

for Future Issuance

Securities to be

Under Equity

Issued Upon

Weighted Average

Compensation Plans

Exercise of

Exercise Price of

(excluding

Outstanding

securities

Options, Warrants

reflected in the

Equity Compensation Plan Category

and Rights

first column)

Stockholder-approved plans (excluding Employee Stock Purchase Plan)

1.2

61.92

3.0

Nonstockholder-approved plans⁽¹⁾

2.0

51.41

4.5

Subtotal (except for weighted average exercise price)

3.2

55.28

7.5

Employee Stock Purchase Plan⁽²⁾

—

2.9

Total

3.2

—

10.4


⁽¹⁾		The table includes the following nonstockholder-approved plans: the 1998 Employee Stock Option Plan, the 2002 Employee Long-Term Incentive Plan and the Director Compensation Deferral Plan. A description of each of these plans is set forth below.

⁽²⁾		The per share purchase price under the Baker Hughes Incorporated Employee Stock Purchase Plan is determined in accordance with section 423 of the Code as 85% of the lower of the fair market value of a share of our common stock on the date of grant or the date of purchase.

Our nonstockholder-approved plans are described below:

1998 Employee Stock Option Plan

The Baker Hughes Incorporated 1998 Employee Stock Option Plan (the “1998 ESOP”) was adopted effective as of October 1, 1998. The number of shares authorized for issuance under the 1998 ESOP is 7.0 million shares. Nonqualified stock options may be granted under the 1998 ESOP to our employees. The exercise price of the options will be equal to the fair market value per share of our common stock on the date of grant, and option terms may be up to ten years. Under the terms and conditions of

the option award agreements for options issued under the 1998 ESOP, options generally vest and become exercisable in installments over the optionee’s period of service, and the options vest on an accelerated basis in the event of a change in control. As of December 31, 2007, options covering approximately 0.2 million shares of our common stock were outstanding under the 1998 ESOP, options covering approximately 0.1 million shares were exercised during fiscal year 2007 and approximately 0.3 million shares remained available for future options.

2002 Employee Long-Term Incentive Plan

The Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (the “2002 Employee LTIP”) was adopted effective as of March 6, 2002. The 2002 Employee LTIP permits the grant of awards as nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, stock awards and cash-based awards to our corporate officers and key employees. The number of shares authorized for issuance under the 2002 Employee LTIP is 9.5 million, with no more than 3.0 million available for grant as awards other than options (the number of shares is subject to adjustment for changes in our common stock).

The 2002 Employee LTIP is the companion plan to the Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan, which was approved by our stockholders in 2002. The rationale for the two companion plans was to discontinue the use of the remaining older option plans and to have only two plans from which we would issue compensation awards.

Options. The exercise price of the options will not be less than the fair market value of the shares of our common stock on the date of grant, and options terms may be up to ten years. The maximum number of shares of our common stock that may be subject to options granted under the 2002 Employee LTIP to any one employee during any one fiscal year will not exceed 3.0 million, subject to adjustment under the antidilution provisions of the 2002 Employee LTIP. Under the terms and conditions of the stock option awards for options issued under the 2002 Employee LTIP, options generally vest and become exercisable in installments over the optionee’s period of service, and the options vest on an accelerated basis in the event of a change in control or certain terminations of employment. As of December 31, 2007, options covering approximately 1.8 million shares of our common stock were outstanding under the 2002 Employee LTIP, options covering approximately 0.9 million shares were exercised during fiscal year 2007 and approximately 3.7 million shares remained available for future options.

Performance Shares and Units; Cash-Based Awards. Performance shares may be granted to employees in the amounts and upon the terms determined by the Compensation Committee of our Board of Directors, but must be limited to no more than 1.0 million shares to any one employee in any one fiscal year. Performance units and cash-based awards may be granted to employees in amounts and upon the terms determined by the Compensation Committee, but must be limited to no more than $10.0 million for any one employee in any one fiscal year. The performance measures that may be used to determine the extent of the actual performance payout or vesting include, but are not limited to, net earnings; earnings per share; return measures; cash flow return on investments (net cash flows divided by owner’s equity); earnings before or after taxes, interest, depreciation and/or amortization; share price (including growth measures and total shareholder return) and Baker Value Added (our metric that measures operating profit after tax less the cost of capital employed).

Restricted Stock and Restricted Stock Units. With respect to awards of restricted stock and restricted stock units, the Compensation Committee will determine the conditions or restrictions on the awards, including whether the holders of the restricted stock or restricted stock units will exercise full voting rights (in the case of restricted stock awards only) or receive dividends and other distributions during the restriction period. At the time the award is made, the Compensation Committee will determine the right to receive unvested restricted stock or restricted units after termination of service. Awards of restricted stock are limited to 1.0 million shares in any one year to any one individual. Awards of restricted stock units are limited to 1.0 million units in any one year to any one individual.

Stock Appreciation Rights. Stock appreciation rights may be granted under the 2002 Employee LTIP on the terms and conditions determined by the Compensation Committee. The grant price of a freestanding stock appreciation right will not be less than the fair market value of our common stock on the date of grant. The maximum number of shares of our common stock that may be subject to stock appreciation rights granted under the 2002 Employee LTIP to any one individual during any one fiscal year will not exceed 3.0 million shares, subject to adjustment under the antidilution provisions of the 2002 Employee LTIP.

Administration; Amendment and Termination. The Compensation Committee shall administer the 2002 Employee LTIP, and in the absence of the Compensation Committee, the Board will administer the Plan. The Compensation Committee will have full and exclusive power to interpret the provisions of the 2002 Employee LTIP as the Committee may deem necessary or proper. The Board may alter, amend, modify, suspend or terminate the 2002 Employee LTIP, except that no amendment, modification, suspension or termination that would adversely affect in any material way the rights of a participant under any award previously granted under the

2002 Employee LTIP may be made without the written consent of the participant. In addition, no amendment of the 2002 Employee LTIP shall become effective absent stockholder approval of the amendment, to the extent stockholder approval is otherwise required by applicable legal requirements.

Director Compensation Deferral Plan

The Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective July 24, 2002 (the “Deferral Plan”), is intended to provide a means for members of our Board of Directors to defer compensation otherwise payable and provide flexibility with respect to our compensation policies. Under the provisions of the Deferral Plan, directors may elect to defer income with respect to each calendar year. The compensation deferrals may be stock option-related deferrals or cash-based deferrals. If a director elects a stock option-related deferral, on the last day of each calendar quarter he or she will be granted a nonqualified stock option. The number of shares subject to the stock option is calculated by multiplying the amount of the deferred compensation that otherwise would have been paid to the director during the quarter by 4.4 and then dividing by the fair market value of our common stock on the last day of the quarter. The per share exercise price of the option will be the fair market value of a share of our common stock on the date the option is granted. Stock options granted under the Deferral Plan vest on the first anniversary of the date of grant and must be exercised within ten years of the date of grant. If a director’s directorship terminates for any reason, any options outstanding will expire three years after the termination of the directorship. The maximum aggregate number of shares of our common stock that may be issued under the Deferral Plan is 0.5 million. As of December 31, 2007, options covering 3,313 shares of our common stock were outstanding under the Deferral Plan, there were no shares exercised during fiscal 2007 and approximately 0.5 million shares remained available for future options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information for this item is set forth in the sections entitled “Corporate Governance-Director Independence” and “Certain Relationships and Related Transactions” in our Proxy Statement, which sections are incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning principal accounting fees and services is set forth in the section entitled “Fees Paid to Deloitte & Touche LLP” in our Proxy Statement, which section is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

List of Documents filed as part of this Report.

	(1)		Financial Statements

			All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

	(2)		Financial Statement Schedules

			Schedule II – Valuation and Qualifying Accounts

	(3)		Exhibits

			Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Annual Report on Form 10-K. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.

	3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

	3.2		Bylaws of Baker Hughes Incorporated restated as of April 26, 2007 (filed as Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	4.1		Rights of Holders of the Company’s Long-Term Debt. The Company has no long-term debt instrument with regard to which the securities authorized there under equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request.

	4.2		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

	4.3		Bylaws of Baker Hughes Incorporated restated as of April 26, 2007 (filed as Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	4.4		Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004).

	10.1+		Employment Agreement by and between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

	10.2+		Change in Control Agreement between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

	10.3+		Indemnification Agreement dated as of October 25, 2004 between Baker Hughes Incorporated and Chad C. Deaton (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on October 7, 2004).

	10.4+		Stock Option Agreement issued to Chad C. Deaton on October 25, 2004 in the amount of 75,000 shares of Company Common Stock (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

	10.5+		Agreement regarding restricted stock award issued to Chad C. Deaton on October 25, 2004 in the amount of 80,000 shares of Company Common Stock (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

	10.6+		Agreement regarding restricted stock award issued to James R. Clark on October 27, 2004 in the amount of 40,000 shares of Baker Hughes Incorporated Common Stock (filed as Exhibit 10.7 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

	10.7+		Second Amended and Restated Stock Matching Agreement by and between Baker Hughes Incorporated and James R. Clark dated as of October 25, 2004 (filed as Exhibit 10.6 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

	10.8+		Letter dated October 26, 2005 to James R. Clark clarifying Mr. Clark’s employment terms (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).

	10.9		Letter Agreement between Baker Hughes Incorporated and James R. Clark dated August 30, 2007 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 31, 2007).

	10.10+		Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated dated as of March 27, 2006 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2006).

	10.11+		Letter Agreement between Baker Hughes Incorporated and David H. Barr dated October 25, 2007 (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2007).

	10.12+		Form of Change in Control Severance Plan (filed as Exhibit 10.8 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.13+

Form of Change in Control Severance Agreement between Baker Hughes Incorporated and David H. Barr and John A. O’Donnell effective as of July 28, 2004, and with James R. Clark and Alan R. Crain, Jr. to be effective as of January 1, 2006 and with Chris P. Beaver, Paul S. Butero and Martin S. Craighead effective as of February 28, 2005 and with Richard L. Williams effective as of May 2, 2005 and with Peter A. Ragauss to be effective as of April 26, 2006 and with Gary G. Rich effective as of September 15, 2006 and with Didier Charreton to be effective as of March 2, 2007 and with Stephen K. Ellison effective as of May 1, 2007 and with Nelson Ney to be effective as of December 13, 2007 (filed as Exhibit 10.8 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

	10.14+		Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

	10.15+		Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

	10.16+		Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of July 24, 2002 (filed as Exhibit 10.16 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

	10.17+*		Baker Hughes Incorporated Executive Severance Plan, as amended and restated on February 7, 2008.

	10.18+*		Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended and restated on February 20, 2008.

	10.19+		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).

	10.20+		First Amendment to Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005, dated February 9, 2007 to be effective January 1, 2007 (filed as Exhibit 10.19 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2006).

	10.21+		Long-Term Incentive Plan, as amended by Amendment No. 1999-1 to Long-Term Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

	10.22+		Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by Amendment No. 1999-1 to 1998 Employee Stock Option Plan (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2003).

	10.23+		Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333-87372 of Baker Hughes Incorporated on Form S-8 filed May 1, 2002).

	10.24+		Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2003).

	10.25+		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 of Baker Hughes Incorporated to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005).

	10.26		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of March 3, 2003 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2003).

	10.27+		Form of Stock Option Agreement for executive officers effective October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

	10.28+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

	10.29+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

	10.30		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

	10.31		Form of Baker Hughes Incorporated Incentive Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

	10.32+		Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

	10.33+		Form of Baker Hughes Incorporated Performance Award Agreement, including Terms and Conditions for certain executive officers (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

	10.34+		Form of Restricted Stock Award Resolution, including Terms and Conditions (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

	10.35+		Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

	10.36+		Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

	10.37*		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement, including Terms and Conditions.

	10.38		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

	10.39		Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

	10.40+		Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors (filed as Exhibit 10.40 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

	10.41+		Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors (filed as Exhibit 10.41 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

	10.42+*		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions.

	10.43+		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

	10.44+		Performance Goals for the Performance Unit Award granted in 2006 (filed as Exhibit 10.43 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

	10.45+		Form of Performance Goals for the Performance Unit Awards (filed as Exhibit 10.44 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2006).

10.46+*

Compensation Table for Named Executive Officers and Directors.

	10.47		Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and fourteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed July 11, 2005).

	10.48		First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on June 12, 2006).

	10.49		Second Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

	10.50		Agreement of Resignation, Appointment and Acceptance by and among Baker Hughes Incorporated, Citibank, N.A. and the Bank of New York Trust Company, N.A. dated as of April 26, 2007, effective May 1, 2007 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	10.51		Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

	10.52		Tax Sharing Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.31 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

	10.53+		Employee Benefits Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

	10.54		Deferred Prosecution Agreement between Baker Hughes Incorporated and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	10.55		Plea Agreement between Baker Hughes Services International, Inc. and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	21.1*		Subsidiaries of Registrant.

	23.1*		Consent of Deloitte & Touche LLP.

	31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated February 21, 2008, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

	31.2*		Certification of Peter A. Ragauss, Chief Financial Officer, dated February 21, 2008, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

	32*		Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief Financial Officer, dated February 21, 2008, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

	99.1		Administrative Proceeding, File No. 3-10572, dated September 12, 2001, as issued by the Securities and Exchange Commission (filed as Exhibit 99.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on September 19, 2001).

	99.2		Baker Hughes Incorporated Information document filed on April 26, 2007, by the United States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.3

Baker Hughes Services International, Inc. Information document filed on April 26, 2007, by the Untied States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	99.4		Sentencing Memorandum and Motion for Waiver of Pre-Sentence Investigation of Baker Hughes Services International, Inc. (filed as Exhibit 99.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	99.5		Baker Hughes Services International, Inc. Sentencing Letter from the United States Department of Justice dated April 24, 2007 (filed as Exhibit 99.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	99.6		The Complaint by the Securities and Exchange Commission vs. Baker Hughes Incorporated filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

	99.7		Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BAKER HUGHES INCORPORATED
Date: February 21, 2008	/s/ CHAD C. DEATON
	Chad C. Deaton
	Chairman of the Board, President and Chief Executive Officer

KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Chad C. Deaton and Peter A. Ragauss, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ CHAD C. DEATON (Chad C. Deaton)	Chairman of the Board, President and Chief Executive Officer (principal executive officer)	February 21, 2008

/s/ PETER A. RAGAUSS (Peter A. Ragauss)	Senior Vice President and Chief Financial Officer (principal financial officer)	February 21, 2008

/s/ ALAN J. KEIFER (Alan J. Keifer)	Vice President and Controller (principal accounting officer)	February 21, 2008

/s/ LARRY D. BRADY	Director	February 21, 2008

(Larry D. Brady)

/s/ CLARENCE P. CAZALOT, JR.	Director	February 21, 2008

(Clarence P. Cazalot, Jr.)

/s/ EDWARD P. DJEREJIAN	Director	February 21, 2008

(Edward P. Djerejian)

/s/ ANTHONY G. FERNANDES	Director	February 21, 2008

(Anthony G. Fernandes)

/s/ CLAIRE W. GARGALLI	Director	February 21, 2008

(Claire W. Gargalli)

/s/ PIERRE H. JUNGELS	Director	February 21, 2008

(Pierre H. Jungels)

/s/ JAMES A. LASH	Director	February 21, 2008

(James A. Lash)

/s/ JAMES F. MCCALL	Director	February 21, 2008

(James F. McCall)

/s/ J. LARRY NICHOLS	Director	February 21, 2008

(J. Larry Nichols)

/s/ H. JOHN RILEY, JR.	Director	February 21, 2008

(H. John Riley, Jr.)

/s/ CHARLES L. WATSON	Director	February 21, 2008

(Charles L. Watson)

Baker Hughes Incorporated

Schedule II – Valuation and Qualifying Accounts


			Additions		Deductions
	Balance at		Charged to		Reversal of						Charged to			Balance at
	Beginning		Cost and		Prior						Other			End of
(In millions)	of Period		Expenses		Deductions⁽¹⁾			Write-offs⁽²⁾			Accounts⁽³⁾			Period


Year ended December 31, 2007:
Reserve for doubtful accounts receivable	$	50.5	$	36.2	$	(14.2	)	$	(10.0	)	$	(3.5	)	$	59.0
Reserve for inventories		211.7		43.4		—			(37.2	)		3.3			221.2

Year ended December 31, 2006:
Reserve for doubtful accounts receivable		51.4		27.5		(20.2	)		(11.3	)		3.1			50.5
Reserve for inventories		201.3		44.9		—			(38.8	)		4.3			211.7

Year ended December 31, 2005:
Reserve for doubtful accounts receivable		50.2		28.3		(14.8	)		(8.0	)		(4.3	)		51.4
Reserve for inventories		220.0		31.4		—			(42.1	)		(8.0	)		201.3


⁽¹⁾		Represents the reversals of prior accruals as receivables are collected.

⁽²⁾		Represents the elimination of accounts receivable and inventory deemed uncollectible or worthless.

⁽³⁾		Represents reclasses, currency translation adjustments and divestitures.

Exhibit Index

Each exhibit identified below is filed as a part of this report. Exhibits designated with an “*” are filed as an exhibit to this Annual Report on Form 10-K. Exhibits designated with a “+” are identified as management contracts or compensatory plans or arrangements. Exhibits previously filed as indicated below are incorporated by reference.


3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

3.2		Bylaws of Baker Hughes Incorporated restated as of April 26, 2007 (filed as Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

4.1		Rights of Holders of the Company’s Long-Term Debt. The Company has no long-term debt instrument with regard to which the securities authorized there under equal or exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of its long-term debt instruments to the SEC upon request.

4.2		Restated Certificate of Incorporation (filed as Exhibit 3.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

4.3		Bylaws of Baker Hughes Incorporated restated as of April 26, 2007 (filed as Exhibit 3.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

4.4		Indenture dated as of May 15, 1994 between Western Atlas Inc. and The Bank of New York, Trustee, providing for the issuance of securities in series (filed as Exhibit 4.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2004).

10.1+		Employment Agreement by and between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.3 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

10.2+		Change in Control Agreement between Baker Hughes Incorporated and Chad C. Deaton dated as of October 25, 2004 (filed as Exhibit 10.2 to Current Report of Baker Hughes Incorporated on Form 8-K filed October 7, 2004).

10.3+		Indemnification Agreement dated as of October 25, 2004 between Baker Hughes Incorporated and Chad C. Deaton (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on October 7, 2004).

10.4+		Stock Option Agreement issued to Chad C. Deaton on October 25, 2004 in the amount of 75,000 shares of Company Common Stock (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.5+		Agreement regarding restricted stock award issued to Chad C. Deaton on October 25, 2004 in the amount of 80,000 shares of Company Common Stock (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.6+		Agreement regarding restricted stock award issued to James R. Clark on October 27, 2004 in the amount of 40,000 shares of Baker Hughes Incorporated Common Stock (filed as Exhibit 10.7 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.7+		Second Amended and Restated Stock Matching Agreement by and between Baker Hughes Incorporated and James R. Clark dated as of October 25, 2004 (filed as Exhibit 10.6 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.8+		Letter dated October 26, 2005 to James R. Clark clarifying Mr. Clark’s employment terms (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).


10.9		Letter Agreement between Baker Hughes Incorporated and James R. Clark dated August 30, 2007 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed August 31, 2007).

10.10+		Letter Agreement between Peter A. Ragauss and Baker Hughes Incorporated dated as of March 27, 2006 (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed March 31, 2006).

10.11+		Letter Agreement between Baker Hughes Incorporated and David H. Barr dated October 25, 2007 (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2007).

10.12+		Form of Change in Control Severance Plan (filed as Exhibit 10.8 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.13+		Form of Change in Control Severance Agreement between Baker Hughes Incorporated and David H. Barr and John A. O’Donnell effective as of July 28, 2004, and with James R. Clark and Alan R. Crain, Jr. to be effective as of January 1, 2006 and with Chris P. Beaver, Paul S. Butero and Martin S. Craighead effective as of February 28, 2005 and with Richard L. Williams effective as of May 2, 2005 and with Peter A. Ragauss to be effective as of April 26, 2006 and with Gary G. Rich effective as of September 15, 2006 and with Didier Charreton to be effective as of March 2, 2007 and with Stephen K. Ellison effective as of May 1, 2007 and with Nelson Ney to be effective as of December 13, 2007 (filed as Exhibit 10.8 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2004).

10.14+		Form of Indemnification Agreement between Baker Hughes Incorporated and each of the directors and executive officers (filed as Exhibit 10.4 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.15+		Baker Hughes Incorporated Director Retirement Policy for Certain Members of the Board of Directors (filed as Exhibit 10.10 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.16+		Baker Hughes Incorporated Director Compensation Deferral Plan, as amended and restated effective as of July 24, 2002 (filed as Exhibit 10.16 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.17+*		Baker Hughes Incorporated Executive Severance Plan, as amended and restated on February 7, 2008.

10.18+*		Baker Hughes Incorporated Annual Incentive Compensation Plan, as amended and restated on February 20, 2008.

10.19+		Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2005).

10.20+		First Amendment to Baker Hughes Incorporated Supplemental Retirement Plan, as amended and restated effective as of January 1, 2005, dated February 9, 2007 to be effective January 1, 2007 (filed as Exhibit 10.19 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2006).

10.21+		Long-Term Incentive Plan, as amended by Amendment No. 1999-1 to Long-Term Incentive Plan (filed as Exhibit 10.18 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.22+		Baker Hughes Incorporated 1998 Employee Stock Option Plan, as amended by Amendment No. 1999-1 to 1998 Employee Stock Option Plan (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2003).

10.23+		Baker Hughes Incorporated 2002 Employee Long-Term Incentive Plan (filed as Exhibit 4.4 to Registration Statement No. 333-87372 of Baker Hughes Incorporated on Form S-8 filed May 1, 2002).

10.24+		Baker Hughes Incorporated 2002 Director & Officer Long-Term Incentive Plan (filed as Exhibit 10.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended September 30, 2003).


10.25+		Amendment to 2002 Director & Officer Long-Term Incentive Plan, effective as of October 27, 2005 (filed as Exhibit 10.3 of Baker Hughes Incorporated to Quarterly Report on Form 10-Q for the quarter ended September 30, 2005).

10.26		Baker Hughes Incorporated Employee Stock Purchase Plan, as amended and restated, effective as of March 3, 2003 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2003).

10.27+		Form of Stock Option Agreement for executive officers effective October 1, 1998 (filed as Exhibit 10.37 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.28+		Form of Nonqualified Stock Option Agreement for directors effective October 25, 1998 (filed as Exhibit 10.39 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2000).

10.29+		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for executive officers, dated January 24, 2001 (filed as Exhibit 10.41 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.30		Form of Baker Hughes Incorporated Nonqualified Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.43 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.31		Form of Baker Hughes Incorporated Incentive Stock Option Agreement for employees, dated January 30, 2002 (filed as Exhibit 10.44 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2001).

10.32+		Form of Baker Hughes Incorporated Stock Option Award Agreements, with Terms and Conditions (filed as Exhibit 10.46 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2002).

10.33+		Form of Baker Hughes Incorporated Performance Award Agreement, including Terms and Conditions for certain executive officers (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

10.34+		Form of Restricted Stock Award Resolution, including Terms and Conditions (filed as Exhibit 10.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2004).

10.35+		Form of Baker Hughes Incorporated Restricted Stock Award Agreement (filed as Exhibit 10.54 to Annual Report on Form 10-K for the year ended December 31, 2004).

10.36+		Form of Baker Hughes Incorporated Restricted Stock Award Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.37*		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement, including Terms and Conditions.

10.38		Form of Baker Hughes Incorporated Restricted Stock Unit Agreement (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.39		Form of Baker Hughes Incorporated Restricted Stock Unit Terms and Conditions (filed as Exhibit 10.54 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2004).

10.40+		Form of Baker Hughes Incorporated Restricted Stock Award, including Terms and Conditions for directors (filed as Exhibit 10.40 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.41+		Form of Baker Hughes Incorporated Stock Option Award Agreement, including Terms and Conditions for directors (filed as Exhibit 10.41 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).


10.42+*		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions.

10.43+		Form of Baker Hughes Incorporated Performance Unit Award Agreement, including Terms and Conditions (filed as Exhibit 10.42 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.44+		Performance Goals for the Performance Unit Award granted in 2006 (filed as Exhibit 10.43 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2005).

10.45+		Form of Performance Goals for the Performance Unit Awards (filed as Exhibit 10.44 of Baker Hughes Incorporated to Annual Report on Form 10-K for the year ended December 31, 2006).

10.46+*		Compensation Table for Named Executive Officers and Directors.

10.47		Form of Credit Agreement, dated as of July 7, 2005, among Baker Hughes Incorporated, JPMorgan Chase Bank, N.A., as Administrative Agent and fourteen lenders for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed July 11, 2005).

10.48		First Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on June 12, 2006).

10.49		Second Amendment to the Credit Agreement dated June 7, 2006, among Baker Hughes Incorporated and fifteen banks for $500 million, in the aggregate for all banks (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

10.50		Agreement of Resignation, Appointment and Acceptance by and among Baker Hughes Incorporated, Citibank, N.A. and the Bank of New York Trust Company, N.A. dated as of April 26, 2007, effective May 1, 2007 (filed as Exhibit 10.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

10.51		Agreement and Plan of Merger among Baker Hughes Incorporated, Baker Hughes Delaware I, Inc. and Western Atlas Inc. dated as of May 10, 1998 (filed as Exhibit 10.30 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.52		Tax Sharing Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.31 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.53+		Employee Benefits Agreement dated October 31, 1997, between Western Atlas Inc. and UNOVA Inc. (filed as Exhibit 10.32 to Annual Report of Baker Hughes Incorporated on Form 10-K for the year ended December 31, 2003).

10.54		Deferred Prosecution Agreement between Baker Hughes Incorporated and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

10.55		Plea Agreement between Baker Hughes Services International, Inc. and the United States Department of Justice filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 10.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

21.1*		Subsidiaries of Registrant.

23.1*		Consent of Deloitte & Touche LLP.

31.1*		Certification of Chad C. Deaton, Chief Executive Officer, dated February 21, 2008, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Peter A. Ragauss, Chief Financial Officer, dated February 21, 2008, pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended.


32*		Statement of Chad C. Deaton, Chief Executive Officer, and Peter A. Ragauss, Chief Financial Officer, dated February 21, 2008, furnished pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934, as amended.

99.1		Administrative Proceeding, File No. 3-10572, dated September 12, 2001, as issued by the Securities and Exchange Commission (filed as Exhibit 99.1 to Current Report of Baker Hughes Incorporated on Form 8-K filed on September 19, 2001).

99.2		Baker Hughes Incorporated Information document filed on April 26, 2007, by the United States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.3		Baker Hughes Services International, Inc. Information document filed on April 26, 2007, by the Untied States Attorney’s Office for the Southern District of Texas and the United States Department of Justice (filed as Exhibit 99.2 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.4		Sentencing Memorandum and Motion for Waiver of Pre-Sentence Investigation of Baker Hughes Services International, Inc. (filed as Exhibit 99.3 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.5		Baker Hughes Services International, Inc. Sentencing Letter from the United States Department of Justice dated April 24, 2007 (filed as Exhibit 99.4 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.6		The Complaint by the Securities and Exchange Commission vs. Baker Hughes Incorporated filed on April 26, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.5 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended March 31, 2007).

99.7		Final Judgment by the Securities and Exchange Commission as to Defendant Baker Hughes Incorporated dated and filed on May 1, 2007, with the United States District Court of Texas, Houston Division (filed as Exhibit 99.1 to Quarterly Report of Baker Hughes Incorporated on Form 10-Q for the quarter ended June 30, 2007).

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

BAKER HUGHES a GE (BHI) 10-K2007 FY Annual report

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