UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10–K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1–9397

Baker Hughes Incorporated

     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 an accelerated filer (as defined in Rule 12b–2 of the Act). YES þ NO o

     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 July 2, 2004 reported by the New York Stock Exchange) was approximately $12,551,384,649.

     As of February 25, 2005, the registrant has outstanding 338,185,465 shares of Common Stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of Registrant’s 2004 Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2005 are incorporated by reference into Part III of this Form 10–K.

Baker Hughes Incorporated

INDEX

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PART I

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 (is there oil, natural gas or water in the spaces). 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 logging–while–drilling (“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 present. 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:

	•	data acquisition efficiency,
	•	the sophistication and accuracy of measurements,
	•	the ability to interpret the information gathered to quantify the hydrocarbons producible from the formation, and
	•	the ability to differentiate services which can run exclusively or more efficiently on wireline from services which can run on either wireline or drill pipe.

     Baker Atlas’ primary formation evaluation and wireline completion and perforating competitors are Schlumberger, Halliburton Company (“Halliburton”), Precision Drilling Corporation, Expro International Group PLC and various other competitors.

     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.

Baker Hughes Drilling Fluids

     Baker Hughes Drilling Fluids is a major provider of drilling fluids (also called “mud”), and a provider of completion fluids (also called “brines”) and fluids environmental services. 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 typically contain barite or bentonite to give them weight that enables the fluid to hold the wellbore open and stabilize it. Additionally, the fluids control downhole pressures and seal porous sections of the wellbore. To ensure maximum efficiency and wellbore stability, drilling fluids are often customized by the wellsite engineer. For drilling through the reservoir itself, Baker Hughes Drilling Fluids’ drill–in or completion fluids possess properties that minimize formation damage. The fluids environmental services of Baker Hughes Drilling Fluids also provide equipment and services to separate the drill cuttings from

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the drilling fluids and re–inject the processed cuttings into a specially prepared well, or to transport and dispose of the cuttings by other means.

     The main driver of customer purchasing decisions in drilling fluids is cost efficiency. Specific opportunities for competitive differentiation include:

	•	improvements in drilling efficiency,
	•	minimizing formation damage, and
	•	the environmentally safe handling and disposal of drilling fluids and cuttings.

     Baker Hughes Drilling Fluids’ primary competitors include Halliburton, M-I, LLC, Newpark Resources, Inc., TETRA Technologies, Inc. and various other competitors.

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

Baker Oil Tools

     Baker Oil Tools is a leading provider of downhole completion, workover and fishing equipment and services.

      Completions. The economic success of a well depends in large part on how the well is completed. Completions are the equipment installed in a well after it is drilled to allow 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 including:

	•	Liner hangers, which suspend a section of steel casing (also called a liner) inside the bottom of the previous section of casing. Its expandable slips grip the inside of the casing and support the weight of the liner below.
	•	Packers, which 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, which controls and adjusts the flow of downhole fluids. Typical flow control devices include sliding sleeves, 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, which 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.
	•	Sand control equipment, which includes gravel pack tools, sand screens and fracturing fluids. These tools and related services are used in loosely consolidated formations to prevent the production of formation sand with the hydrocarbons.
	•	Advanced completion technologies, which include multilateral systems, intelligent well systems and expandable metal technologies. Multilateral completion systems enable two or more zones to be produced from a single well, using multiple horizontal branches. Intelligent Completions® use real–time, remotely operated downhole systems to control the flow of hydrocarbons from one or more zones. Expandable metal technology involves the permanent downhole expansion of a variety of tubular products used in drilling, completion and well remediation applications.

      Workovers. Workover products and services seek to improve, maintain or restore economical production from an already producing well. In this area, Baker Oil Tools provides service tools and inflatable products to repair and stimulate new and existing wells. Service tools function as surface–activated, downhole sealing and anchoring devices to isolate a portion of the wellbore. 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. An inflatable packer expands 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 can also set in “open hole” as opposed to conventional tools which can only be set inside casing. Thru–tubing inflatables enable remedial operations in producing wells. This results in cost savings as rig requirements are lower and workovers can occur without having to remove the completion, which can be very costly.

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      Fishing. Baker Oil Tools is a leading provider of specialized fishing services and equipment that 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. Other fishing services include cleaning wellbores and milling windows in the casing to drill a “sidetrack” or multilateral well.

     The main drivers of customer purchasing decisions in completions, workovers and fishing 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:

	•	the engineering and manufacturing of superior quality products,
	•	reduced well construction costs,
	•	enhanced production and ultimate recovery,
	•	minimized risks, and
	•	reliable performance over the life of the well, particularly in harsh environments and critical wells.

     Baker Oil Tools’ primary competitors in completions are Halliburton, Schlumberger, Weatherford International Ltd. (“Weatherford”), BJ Services Company and various other competitors. Its primary competitors in workover are Halliburton, Schlumberger, Weatherford and various other competitors. Its major competitors in fishing are Smith International, Inc. (“Smith”), Weatherford and various other competitors.

     Key business drivers for Baker Oil Tools include the number of drilling and workover rigs operating, 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 a number of industries, primarily oil and natural gas production, but also including refining, pipeline transportation, petrochemical, agricultural and iron and steel manufacturing. Additionally, Baker Petrolite provides polymer–based products to a broad range of industrial and consumer markets.

     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:

	•	Hydrate inhibitors – Natural gas hydrates are solid ice–like crystals that can form in production flowlines and tubing, causing 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 (“H 2 S”) 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 H 2 S scavengers.

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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 which allow the water component of the emulsion to be separated from the oil.

     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 environmentally friendly cleaners that decontaminate refinery equipment and petrochemical vessels at a lower cost than other methods.

     Through its Pipeline Management Group (“PMG”), Baker Petrolite also 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 usage. 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.

     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.

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

	•	improved levels of production or throughput,
	•	reduced maintenance costs and frequency,
	•	lower treatment costs,
	•	lower treatment intervals, and
	•	successful resolution of environmental issues.

     Baker Petrolite’s primary oilfield specialty chemical competitors are GE Water Technologies, Nalco Company, Champion Technologies and various other competitors.

     Key business drivers for Baker Petrolite include oil and natural gas production levels, the number of producing wells, 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 high 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 surface controller. 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 onshore or offshore applications and are primarily used in mature oil producing 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.

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     Specific opportunities for competitive differentiation include:

	•	system reliability,
	•	system run–life,
	•	optimizing production,
	•	operating efficiency, and
	•	service delivery.

     Centrilift’s primary competitors in the ESP market are Schlumberger, John Wood Group PLC and various other competitors and in the PCP market are Weatherford, Robbins & Myers, Inc. and various other competitors.

     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 the removal of water from coal bed methane wells.

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 hole 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. 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 distance drilled. Specific opportunities for competitive differentiation include:

	•	improving the rate of penetration,
	•	extending bit life, 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 are Smith, Halliburton, Grant Prideco, Inc. and various other competitors.

     Key business drivers for Hughes Christensen include the number of drilling rigs operating, 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 LWD services.

      Directional Drilling . Directional drilling services are used to guide a well along a predetermined path 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.

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     INTEQ is a leading supplier of both conventional and rotary based directional drilling systems. Conventional directional drilling systems employ a downhole motor which 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 are.

     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.

      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 fluid 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,
	•	equipment reliability,
	•	the optimal placement of the wellbore in the reservoir, and
	•	the quality of the wellbore.

     INTEQ’s primary competitors in drilling and evaluation services are Halliburton, Schlumberger and various other competitors.

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

WesternGeco

     WesternGeco is a seismic venture in which we own 30% and Schlumberger owns 70%. WesternGeco provides comprehensive worldwide reservoir imaging, monitoring and development services, with one of the most extensive seismic crews and data processing centers in the industry, as well as one of the world’s largest multiclient seismic libraries. Services range from 3D and time–lapse (4D) seismic surveys to multicomponent surveys for delineating prospects and reservoir management. WesternGeco is positioned to meet the full range of customer needs in land, marine, and shallow–water transition–zone areas.

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     Seismic solutions include proprietary Q–Technology* for enhanced reservoir description, characterization and monitoring throughout the life of the field – from exploration through enhanced recovery. Q* single–sensor hardware and software are setting a new quality and capability standard for seismic solutions.

     WesternGeco’s Omega* Seismic Processing System encompasses one of the industry’s most advanced and comprehensive suites of algorithms and runs on multiplatform technology, ensuring timely turnaround for even the most complex processing projects. WesternGeco’s major competitors are Compagnie Generale de Geophysique, Veritas DGC, Inc. and Petroleum Geo-Services ASA.

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

* Mark of WesternGeco

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 supply stores, independent distributors, agents, licensees or sales representatives. We ordinarily provide technical and advisory services to assist in our customers’ use of our products and services. Stock points and service centers for our products and services are located in areas of drilling and production activity throughout the world.

     Our products and services are sold in highly competitive markets, and revenues and earnings can be affected by changes in competitive prices, fluctuations in the level of drilling, workover and completion activity in major markets, general economic conditions, foreign currency exchange fluctuations and governmental regulation. 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.”

INTERNATIONAL OPERATIONS

     We operate in over 90 countries worldwide, and our operations are subject to the risks inherent in doing business in multiple countries with various laws and differing political environments. These risks include, but are not limited to: war, boycotts, political and economic changes, corruption, terrorism, expropriation, foreign currency exchange controls, taxes and changes in foreign currency exchange rates. Although it is impossible to predict the likelihood of such occurrences or their effect on us, division and corporate management 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, 2004, see Note 17 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. While we regard patent and trademark protection as important to our business and future prospects, we consider our established reputation, 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 of a critical nature to our business.

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RAW MATERIALS

     We purchase various raw materials and component parts for use in manufacturing our products. The principal materials we purchase are steel alloys (including chromium and nickel), titanium, beryllium, copper, tungsten carbide, synthetic and natural diamonds, printed circuit boards and other electronic components and hydrocarbon–based chemical feed stocks. All of these materials are available from numerous sources and could be subject to rising costs. We have not experienced any 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 any significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

OTHER DEVELOPMENTS

     In October 2003, we signed a definitive agreement for the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and recorded charges totaling $37.4 million, net of tax of $10.9 million, which consisted of a loss of $13.5 million on the write down of BIRD to fair value, $6.2 million of severance and warranty accruals and a loss of $17.7 million related to the recognition of cumulative foreign currency translation adjustments into earnings. In January 2004, we completed the sale of BIRD and recorded an additional loss on the sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments. The adjustments were the result of changes in the value of assets sold to and liabilities assumed by the buyer between the date the initial sales price was negotiated and the closing of the sale.

     In February 2004, we completed the sale of our minority interest in Petreco International for $35.8 million, of which $7.4 million is held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We recognized a gain on the sale of $1.3 million, net of tax of $1.5 million.

     In September 2004, we completed the sale of Baker Hughes Mining Tools, a product line group within the Oilfield segment that manufactured rotary drill bits used in the mining industry, for $31.5 million. We recorded a gain on the sale of $0.2 million, net of tax of $3.6 million, which consisted of a gain on disposal of $6.8 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings.

EMPLOYEES

     At December 31, 2004, we had approximately 26,900 employees, as compared with approximately 26,500 employees at December 31, 2003. Approximately 2,300 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 28, 2005, the name of each of our executive officers, together with his age and all offices presently held.

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     There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

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

     We are involved in voluntary remediation projects at some of our present and former manufacturing facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency–issued consent decree or agreed order. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based on internal evaluations and are not discounted. Such accruals are recorded when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.

     During the year ended December 31, 2004, we spent approximately $24.4 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. In 2005, we expect to spend approximately $26.4 million to comply with Environmental Regulations. 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.

     During the year ended December 31, 2004, we incurred approximately $2.3 million in capital expenditures for environmental control equipment, and we estimate we will incur approximately $3.9 million during 2005. We believe these capital expenditures for environmental control equipment will not have a material adverse effect upon our consolidated financial statements because the aggregate amount of these expenditures is not expected to be material.

     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 and 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 PRPs 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. At December 31, 2004, we have accrued $3.6 million of remediation costs related to the sites detailed below. When used in the descriptions of the sites below, the word de minimis refers to the smallest PRPs, whose contribution rate is usually less than 1%.

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(a)

Baker Petrolite, Hughes Christensen, an INTEQ predecessor entity, Baker Oil Tools and a former subsidiary were named in April 1984 as PRPs at the Sheridan Superfund Site located in Hempstead, Texas. The Texas Commission on Environmental Quality (“TCEQ”) is overseeing the remedial work at this site. The Sheridan Site Trust was formed to manage the site remediation and we participate as a member. Based on the use of new remedial technologies, the 2004 cost projections for full remediation have been reduced from $30 million to $6 million, of which $1.0 million has been collected. Our contribution is approximately 1.8% of the estimated $5 million in remaining costs.

(b)

In December 1987, one of our former subsidiaries was named a respondent in an EPA Administrative Order for Remedial Design and Remedial Action associated with the Middlefield–Ellis–Whisman Study Area, an eight square mile soil and groundwater contamination site located in Mountain View, California. As a result of the environmental investigations and a resulting report delivered to the EPA in September 1991, the EPA has informed us that no further work needs to be performed on the site. In fact, the EPA has indicated that it does not believe there is a contaminant source on the property. We signed a settlement agreement in March 2004, which transferred any future liability for investigation and remediation at the site to the PRP group. The settlement amount was not material.

(c)

In 1997, we entered into a settlement agreement with Prudential Insurance Company (“Prudential”) regarding cost recovery for the San Fernando Valley – Glendale Superfund. One of our predecessors operated on the Prudential property in Glendale. Prudential was identified as a PRP for the Glendale Superfund. Prudential instituted legal proceedings against us for cost recovery under CERCLA. Without any admission of liability, we agreed to pay 40% of Prudential’s costs attributed to cleanup at the site, limited to a cap of $0.3 million. A pump and treat system was selected as the cleanup remedy at Glendale, and it is expected to operate until 2012. We continue to contribute our portion of ongoing assessments to fund this remediation strategy.

(d)

In June 1999, the EPA named a Hughes Christensen predecessor as a PRP at the Li Tungsten Site in Glen Cove, New York. We contributed a de minimis amount of hazardous substances to the site. In December 2004, the EPA issued us a special de minimis settlement offer based on the fact that our contribution was limited to metals contamination, not radiological contamination, at the site. The settlement offer has been signed and is not material.

(e)

In January 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. The cost estimate for remediation of the site is approximately $14 million. The combined volume that we contributed to the site is estimated to be less than 0.5% for liquids and 0.25% for solids.

(f)

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 TCEQ is overseeing the investigation and remediation at the Force Road State Site. We participate as a member of the technical committee to effectively manage the project, since our contribution is estimated to be 71%. The initial investigation at the site is complete and a detailed report has been submitted to the TCEQ along with a proposed work plan. The most current cost projections for closure of the site are in the range of $5 million to $7 million; however, this projection may change once the remedial options are fully evaluated.

(g)

In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and two 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. The EPA has engaged in some emergency removal actions at the site. The investigation is underway and when complete, remedial options will be developed and submitted to the EPA for evaluation. The initial estimate for cleanup at the Malone site is $82 million; however, this is subject to change since the final remedial plan has not been selected. Our total contribution is estimated at approximately 1.7%.

(h)

In January 2003, Western Atlas International, Inc., its predecessor companies and Baker Hughes Oilfield Operations, Inc. were identified as PRPs in the Gulf Nuclear Superfund site in Odessa, Texas. The EPA conducted an emergency removal at the site in 2000. Total investigation and cleanup costs are estimated by the EPA to be approximately $24 million. A preliminary settlement proposal has been issued for review, and our settlement cost is not expected to be material.

(i)

In September 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 de minimis parties was delayed, but is expected in 2005. The EPA and Steering Committee estimate cleanup costs in excess of $650 million. As of January 2005, there was insufficient information to estimate our potential contribution to these cleanup costs.

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(j)

In October 2003, Baker Petrolite was notified by the EPA of their potential involvement at the Cooper Drum Superfund site located in South Gate, California. At this time there is no estimate available for cleanup costs and, accordingly, there is insufficient information to estimate our potential contribution.

(k)

In April 2004, we were notified that Baker Petrolite was included in the Container Recycling Superfund site in Kansas City, Kansas. We are a major PRP at the site, which was a former drum recycler used by a predecessor company to Baker Petrolite. The EPA estimates outstanding remedial costs of $1.7 million, with our contribution estimated to be 4% to 7% of these costs.

     In addition to the sites mentioned above, there are four Superfund sites where we have ongoing obligations. The remedial work at most of these sites has been completed and remaining operations are limited to groundwater recovery and/or monitoring. The monitoring phase can continue for up to 30 years. Our aggregate cost for these sites is estimated to be less than $0.1 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. 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 established adequate reserves to cover the estimate we presently believe will be our ultimate liability with respect to 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 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. See Note 16 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, 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.

     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 geographic area:

liabilities to governmental authorities in Nigeria. The investigation in Nigeria was substantially completed during the first quarter of 2003 and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our consolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the investigations has been provided to the SEC and DOJ.

     The Department of Commerce, Department of the Navy and the DOJ (the “U.S. agencies”) are investigating compliance with certain export licenses issued to Western Geophysical from 1994 through 2000 for export of seismic equipment leased by the People’s Republic of China. We acquired Western Geophysical in August 1998 and subsequently transferred related assets to WesternGeco in December 2000. Under the WesternGeco formation agreement, we owe indemnity to WesternGeco for certain matters. We are cooperating fully with the U.S. agencies.

     We have received a subpoena from a grand jury in the Southern District of New York regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations Oil-for-Food Program (the “U.N. Program”). We have also received a request from the SEC to provide a written statement and certain information regarding our participation in the U.N. Program. We are responding to both the subpoena and the request. Other companies in the energy industry are believed to have received similar subpoenas and requests.

     The U.S. agencies, the SEC and other authorities have a broad range of civil and criminal sanctions they may seek to impose against corporations and individuals in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. During 2004, such agencies and authorities entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed, including in some cases multi–million dollar fines and other sanctions. It is not possible to accurately predict at this time when any of the investigations related to the Company will be completed. Based on current information, we cannot predict the outcome of such investigations or what, if any, actions may be taken by the U.S. agencies, the SEC or other authorities or the effect it may have on our consolidated financial statements.

     On May 10, 2004, the District Court of Andrews County, Texas entered a judgment in favor of LOTUS, LLC and against INTEQ in the amount of $14.8 million for lost profits resulting from a breach of contract in drilling a well to create a salt cavern for disposing of naturally occurring radioactive waste. We have filed an appeal and taken other actions. We believe that any liability that we may incur as a result of this litigation would not have a material adverse financial effect on our consolidated financial statements.

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

     The following table contains information about our purchases of equity securities during the fourth quarter of 2004.

Issuer Purchases of Equity Securities

(1)	Represents shares purchased from employees to pay the option exercise price related to stock–for–stock exchanges in option exercises under employee benefit plans.

(2)

On September 10, 2002, we announced a plan to repurchase from time to time up to $275 million of our outstanding common stock. No shares were repurchased in 2004 under the plan. The plan has no expiration date, but may be terminated by the Board of Directors at any time. Under the plan, we have authorization remaining to repurchase up to $44.5 million in common stock.

(3)

On September 3, 2004, we announced the commencement of a voluntary sale program (also known as an odd–lot program) for stockholders owning fewer than 100 shares of our common stock. The shares were sold on the open market by the program’s administrator, Mellon Investor Services LLC. The program was not conditioned on receipt of a minimum number of tenders and expired on November 5, 2004.

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ITEM 6. SELECTED FINANCIAL DATA

     The Selected Financial Data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

NOTES TO SELECTED FINANCIAL DATA

(1)

Discontinued operations. The selected financial data has been reclassified to reflect 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)

WesternGeco. In November 2000, we formed the WesternGeco venture with Schlumberger by transferring the seismic fleets, data processing assets, exclusive and nonexclusive multiclient surveys and other assets of our Western Geophysical division. We own 30% of the venture and Schlumberger owns 70%, and we account for this investment using the equity method of accounting.

(3)

Restructuring charges (reversals). See Note 4 of the Notes to Consolidated Financial Statements in Item 8 herein for a description of the restructuring charge reversal in 2003. During 2000, we recorded a restructuring charge of $29.5 million related to our plan to substantially exit the oil and natural gas exploration business. The major actions included in this restructuring were a reduction in workforce, costs to settle contractual obligations and a loss on the write–off of our undeveloped exploration properties in certain foreign jurisdictions. In 2000, we also recorded a $6.0 million restructuring charge in connection with the

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	formation of WesternGeco and recorded a reversal of $28.5 million of restructuring charges recorded in 1999. Included in the costs to settle contractual obligations was $4.5 million for the minimum amount of our share of project costs relating to our interest in an oil and natural gas property in Colombia. After unsuccessful attempts to negotiate a settlement with our joint venture partner, we decided to abandon further involvement in the project. Subsequently, in 2001, a third party agreed to assume the remaining obligation in exchange for our interest in the project. Accordingly, we reversed $4.2 million related to this obligation.
(4)	(Gain) loss on disposal of assets. During 2000, we recorded a loss of $75.5 million on the sale of our interests in certain oil and natural gas properties and recorded gains of $7.6 million on the sale of various product lines.
(5)	Cumulative effect of accounting change. In 2003, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations . In 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets . In 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended by SFAS No. 137 and 138.

net of tax, of $105.9 million related to our share of a WesternGeco restructuring charge and $45.3 million related to the impairment of our investment in WesternGeco. Both our revenues and operating profits set all time records in 2004.

     During 2004, the Baker Hughes rig count rose to its highest level since 1986, as oil and natural gas companies around the world recognized the need to increase productive capacity to meet the growing demand for hydrocarbons. Oil and natural gas prices were at historic highs in 2004, reflecting strong demand and relatively low inventories. The lack of excess productive capacity and several geopolitical and weather events also contributed to higher and more volatile commodity prices in 2004. In 2004, our revenues increased 16.2% compared with 2003, outpacing the 10.1% increase in the worldwide average rig count for 2004 compared with 2003. In North America, our 2004 revenues increased 14.4% compared with 2003, while the rig count increased 10.9% for 2004 compared with 2003, driven primarily by land–based drilling for natural gas. Outside North America, our 2004 revenues increased 17.5% compared with 2003, while the rig count increased 8.6% for 2004 compared with 2003. Revenue growth was particularly noteworthy in Russia and the Caspian region, Latin America, the Middle East, Africa and Asia. Our European revenues in 2004 were up modestly compared with 2003, despite a 15.2% drop in the North Sea rig count.

     The critical success factors for our business are embodied in our long–term strategy, which we call our Strategic Framework. This strategy includes the development and maintenance of a high performance culture founded on our Core Values and Keys to Success; our product line focused organization and our focus on best–in–class opportunities; maintaining our financial flexibility and financial discipline; and execution of our strategies for product development and commercialization, manufacturing quality and service quality.

     Our ongoing effort to develop and maintain a high performance culture starts with our Core Values of integrity, teamwork, performance and learning and with our Keys to Success. We employ succession planning efforts to develop leaders across all our businesses that embody these Core Values and represent the diversity of our customer base. We hire and train employees from around the world to ensure that we have a well–trained workforce in place to support our business plans.

     Our focus on best–in–class opportunities starts with our product line focused organization structure. We believe that through our product line focused divisions, we develop the technologies that deliver best–in–class value to our customers. As an enterprise, we are also focused on those markets that we believe provide best–in–class opportunities for growth. Our management team has identified markets for immediate focus including Russia and the Caspian region and NOCs.

     Our focus on financial flexibility and financial discipline is the backbone of our effort to deliver differential growth at superior margins while earning an acceptable return on our investments throughout the business cycle. Investments are given priority and funded depending on their ability to provide risk–adjusted returns in excess of our cost of capital. Our effort to obtain the best price we can for our products and services begins with our approach to capital discipline. Over the past few years, we have invested for growth in our business, repaid debt, paid dividends and repurchased stock, and we expect to maintain the flexibility to be able to undertake such activities in the future.

     The last element of our Strategic Framework focuses on our ability to identify, develop and commercialize new products and services that will lead to differential growth at superior margins in our business. The effort extends to every phase of our operations, including continuous improvement programs in our manufacturing facilities and field operations that support our goal of flawless execution at the well site.

     The execution of our 2005 business plan and the ability to meet our 2005 financial objectives are dependent on a number of factors. These factors include, but are not limited to, our ability to: manage raw material and component costs (especially steel alloys, copper and chemicals) which are expected to increase in 2005 compared with 2004; continue to make ongoing improvements in the productivity of our manufacturing organization; recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; expand our business in areas that are growing rapidly (such as Russia and the Caspian region) with customers whose spending is expected to increase the most rapidly (such as NOCs), and in areas in which we are underrepresented (such as the Middle East); and realize price increases commensurate with the value we provide to our customers. For a full discussion of risk factors and forward–looking statements, please see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry”, “Risk Factors Related to Our Business” and “Forward–Looking Statements” sections contained herein.

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BUSINESS ENVIRONMENT

     Our business environment and its corresponding operating results are significantly affected by the level of energy industry spending for the exploration and production (“E&P”) of oil and natural gas reserves. An indicator for this spending is the rig count because when drilling and workover rigs are active, many of the products and services provided by the oilfield services industry are required. Our products and services are used during the drilling and workover phases, during the completion of the oil and natural gas wells and during actual production of the hydrocarbons. This E&P spending by oil and natural gas companies is, in turn, influenced strongly by expectations about the supply and demand for oil and natural gas products and by current and expected prices for both oil and natural gas. Rig counts, therefore, generally reflect the relative strength and stability of energy prices.

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 and onshore China, because this information is extremely difficult to obtain.

     North American rigs are counted as active if, on the day the count is taken, the well being drilled has been started, drilling has not been completed and the well is anticipated to be of sufficient depth to be a potential consumer of our drill bits. In most international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. 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. In some active international areas where better data is available, a weekly or daily average of active rigs is taken.

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

     The U.S. – land and inland waters rig count increased 18.5% in 2004 compared with 2003 due to the increase in drilling for natural gas. The U.S. – offshore rig count decreased 10.2% in 2004 compared with 2003 primarily related to a reduced level of spending by major diversified oil and natural gas companies who have continued to redirect a portion of their spending towards larger international projects. The Canadian rig count decreased 1.9%, primarily as a result of unusually wet weather in the summer and fall of 2004.

     Outside North America, the rig count increased 8.6% in 2004 compared with 2003. The rig count in Latin America increased 18.9% in 2004 compared with 2003, driven primarily by spending increases in Mexico, Venezuela and Argentina. The North Sea rig count decreased 15.2% in 2004 compared with 2003 primarily driven by continued declines in drilling activity in both the U.K. and Norwegian sectors. Increases in spending in the North Sea by independent oil and natural gas companies were not large enough to offset decreases in spending by major diversified oil and natural gas companies, which continue to redirect spending towards other larger international projects, especially in Russia and the Caspian region. The rig count in Africa declined 9.3% in 2004 compared with 2003 primarily due to project delays in West Africa. Activity in the Middle East continued to rise steadily, with a 9.0% increase in the rig count in 2004 compared with 2003. The rig count in the Asia Pacific region was up 11.3% in 2004 compared with 2003 primarily due to activity increases in India, Indonesia, Australia and offshore China.

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Oil and Natural Gas Prices

     Generally, changes in the current price and expected future prices of oil or natural gas drive both 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.

     Oil prices averaged a historic high of $41.51/Bbl in 2004. Prices increased from the low $30s/Bbl in January 2004 to a high of $56.17/Bbl in late October 2004, before moderating and ending the year in the low $40s/Bbl. Inventories of crude and petroleum products were relatively low throughout the year, supporting high prices. Worldwide demand for hydrocarbons was driven by strong worldwide economic growth, which was particularly strong in China and developing Asia. Worldwide excess productive capacity was at the lowest level in 30 years, and disruptions, or the potential for disruptions, in oil supply resulted in volatile oil prices throughout the year. Events in 2004 which either disrupted, or had the potential to disrupt, oil supplies included: the August recall elections in Venezuela; sabotage of Iraqi oil production assets; actions taken by the Russian government regarding Yukos and their tax obligations; terrorism in the Middle East, including the possibility of a disruption in oil supply from Saudi Arabia; labor strikes in Norway; labor strikes and violence in Nigeria; and weather, especially the impact of hurricanes in the Gulf of Mexico. By the end of the year, a number of these issues were resolved without significant disruptions to oil supply, which led to oil prices of just above $40/Bbl. In addition to these events, the weakness of the U.S. dollar relative to many worldwide currencies contributed to high U.S. dollar–denominated oil prices.

     During 2004, natural gas prices averaged a historic high of $5.90/mmBtu. Throughout the year, a tight balance between supply and demand supported prices between $5/mmBtu and $7/mmBtu, with weather related spikes outside of this range. High natural gas drilling activity in 2004 combined with increasing depletion rates resulted in limited production growth. We began the year with U.S. natural gas storage levels slightly greater than the five–year average storage levels. Natural gas prices peaked above $7/mmBtu in January as a result of colder than normal winter weather. Prices fell to just above $5/mmBtu in late February, as winter weather moderated and storage remained just above the five–year average. However, by the end of the winter heating season, natural gas inventories fell below the five–year average. In the first half of the summer, the market required natural gas prices in excess of $6/mmBtu in order to limit consumption of natural gas and allow storage to refill. In July and August, below average summer temperatures allowed storage to fill more rapidly and, as storage increased above the five–year average, prices fell to a low of $4.40/mmBtu in early September. High oil prices, hurricane–driven supply disruptions and the start of the winter heating season resulted in a peak price of $8.14/mmBtu in late October. Prices fell below $5/mmBtu in November, as the beginning of the winter was milder than normal and storage was above the five–year average. A late December cold snap resulted in a natural gas price in excess of $7/mmBtu. Prices ended the year at approximately $6/mmBtu.

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,” “Risk Factors Related to Our Business” 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.

      Oil – Oil prices in 2005 are expected to trade between $35/Bbl and $55/Bbl. Continuing the trend from 2004, low inventories of crude oil and products, combined with strong worldwide economic growth, are expected to support prices that could average above $40/Bbl. Growth in oil demand is expected to slow in 2005 compared with 2004, as worldwide economic growth and, in particular, economic growth in China moderates from the extraordinarily strong growth exhibited in 2004. The ongoing lack of excess productive capacity will leave the energy markets susceptible to price volatility should there be any disruptions or threat of disruptions in oil supplies.

     Factors that could lead to prices at the lower end of our range include but are not limited to: a more significant than expected slowing of worldwide economic growth, particularly economic growth in China; greater than planned growth in Russian oil exports; Organization of Petroleum Exporting Countries (“OPEC”) exports in excess of their stated goals; or other factors which result in oil inventories increasing significantly from historically low levels.

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     Factors that could lead to prices at the top of our range include but are not limited to: more rapid than planned expansion of the worldwide economy, particularly the economy in China; a significant slowing of exports from Russia; or other factors which result in oil inventories that remain at historically low levels.

     Factors that could lead to disruptions or the threat of disruptions in oil supply and volatility in oil prices include but are not limited to: terrorist attacks targeting oil production from Saudi Arabia or other key producers; labor strikes in key oil producing areas such as Nigeria; the potential for other military actions in the Middle East; and adverse weather conditions, especially in the Gulf of Mexico. The potential for these and other events to cause volatility will be mitigated by the degree to which OPEC, and in particular Saudi Arabia, are able to increase excess productive capacity.

      Natural Gas – Natural gas prices in 2005 are expected to remain volatile, trading between $4/mmBtu and $7/mmBtu. Natural gas prices could trade at the top of this range if weather is colder than normal, the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of customer spending are not sufficient to support the production growth required to meet the growth of natural gas demand. Natural gas prices could move to the bottom of this range if the U.S. economic recovery is weaker than expected or weather is milder than expected. During the summer, natural gas prices are expected to trade at a level necessary to curtail price sensitive demand and allow storage to refill.

      Customer Spending – Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices described above, anticipated customer spending trends are as follows:

	•	North America – Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 7% to 9% in 2005 compared with 2004.
	•	Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase 10% to 14% in 2005 compared with 2004.
	•	Total spending is expected to increase 9% to 12% in 2005 compared with 2004.

      Drilling Activity – Based upon our outlook for oil and natural gas prices and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count, is as follows:

	•	The North American rig count is expected to increase approximately 4% to 6% in 2005 compared with 2004.
	•	Drilling activity outside of North America is expected to increase approximately 9% to 11% in 2005 compared with 2004.

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 are centered on those factors that impact, either positively or negatively, the markets for oil and natural gas. Key risk factors currently influencing the worldwide oil and natural gas markets are discussed below.

•	Excess productive capacity – the impact of supply and demand disruptions on oil prices and oil price volatility is tempered by the size of the disruption relative to the excess productive capacity. Key measures include estimates of worldwide productive capacity as compared with worldwide demand.
•	Supply disruptions – the loss of production, the inability to export and/or delay of activity from key oil exporting countries, including but not limited to, Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela, due to political instability, civil unrest, labor issues or military activity. In addition, adverse weather such as hurricanes could impact production facilities, causing supply disruptions.
•	Energy prices and price volatility – the impact of widely fluctuating commodity prices on the stability of the market and subsequent impact on customer spending. While current energy prices are important contributors to positive cash flow at E&P companies, expectations for future prices and price volatility are generally more important for determining future E&P spending. While higher commodity prices generally lead to higher levels of E&P spending, sustained high energy prices can be an impediment to economic growth.
•	Global economic growth – particularly the impact of the U.S. and Western European economies and the economic activity in Japan, China, South Korea and the developing areas of Asia where the correlation between economic growth and energy demand

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	is strong. The strength of the U.S. economy and economic growth in developing Asia, particularly China, will continue to be important in 2005. Key measures include U.S. and international economic output, global energy demand and forecasts of future demand by governments and private organizations.
•	Oil and natural gas storage inventory levels – an indicator of the balance between supply and demand. A key measure of U.S. natural gas inventories is the storage level reported weekly by the U.S. Department of Energy compared with historic levels. Key measures for oil inventories include U.S. inventory levels reported by the U.S. Department of Energy and the American Petroleum Institute and worldwide estimates reported by the International Energy Agency.
•	Production control – the degree to which individual OPEC nations and other large oil and natural gas producing countries, including, but not limited to, Mexico, 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. Key measures of production control include actual production levels compared with target or quota production levels, oil prices compared with targeted oil prices and changes in each country’s market share.
•	Ability to produce natural gas – the amount of natural gas that can be produced is a function of the number and productivity of new wells drilled, completed and connected to pipelines 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. Key measures include government and private surveys of natural gas production, company reported production, estimates of reservoir depletion rates and drilling and completion activity.
•	Impact of energy prices and price volatility on demand for hydrocarbons – short–term price changes can result in companies switching to the most economic sources of fuel, prompting a temporary curtailment of demand, while long–term price changes can lead to permanent changes in demand. These changes in demand result in the oilfield services industry being cyclical in nature. Key indicators include hydrocarbon prices on a Btu equivalent basis and indicators of hydrocarbon demand, such as electricity generation or industrial production.
•	Access to prospects – the ability of oil and natural gas companies to develop economically attractive projects based on their expectations of future energy prices, required investments and resulting returns. Access to prospects may be limited because host governments do not allow access to the reserves or because another oil and natural gas company owns the rights to develop the prospect.
•	Weather – the impact of variations in temperatures as compared with normal weather patterns and the related effect on demand for oil and natural gas. A key measure of the impact of weather on energy demand is population–weighted heating and cooling degree days as reported by the U.S. Department of Energy and forecasts of warmer than normal or cooler than normal temperatures. Weather can also impact production, for example, in the North Sea, the Gulf of Mexico and Canada.
•	Access to capital – the ability of oil and natural gas companies to access the funds necessary to carry out their E&P plans. Access to capital is particularly important for smaller independent oil and natural gas companies. Key measures of access to capital include cash flow, interest rates, analysis of oil and natural gas company leverage and equity offering activity.
•	Technological progress – the design and application of new products that allow oil and natural gas companies to drill fewer wells and to drill, complete and produce wells faster, recover more hydrocarbons and/or lower costs. Key measures also include the overall level of research and engineering spending by oilfield services companies and the pace at which new technology is both introduced commercially and accepted by customers.
•	Pace of new investment – the investment by oil and natural gas companies in emerging markets and any impact it has on their spending in areas where they already have an established presence.
•	Maturity of the resource base – the growing necessity for increased levels of investment and activity to support production from an area the longer it is developed. Key measures include changes in undeveloped hydrocarbon reserves in mature areas like the North Sea, the U.S., Canada and Latin America.
•	Government regulations – the costs incurred by oil and natural gas companies to conform to and comply with government regulations, including environmental regulations, may limit the quantity of oil and natural gas that may be economically produced.

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     For additional risk factors and cautions regarding forward–looking statements, see the “Risk Factors Related to Our Business” and the “Forward–Looking Statements” sections contained herein. This list of risk factors is not intended to be all inclusive.

BUSINESS OUTLOOK

     In our outlook for 2005, we took into account the factors described herein. We expect that 2005 will be a stronger year than 2004, with revenues increasing 9% to 11%, in line with the expected increase in customer spending. We expect that the growth in our revenues will primarily be due to increased activity and, to a lesser extent, price improvement. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China, and OPEC discipline, resulting in an average oil price exceeding $35/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding an average of $5/mmBtu.

     In North America, we expect revenues to increase 11% to 13% in 2005 compared with 2004, with the majority of the increase occurring in the second half of 2005. We expect spending on land–based projects to continue to increase in 2005 driven by demand for natural gas, following the trend evident in 2004. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2005 compared with 2004. The normal weather–driven seasonal decline in U.S. and Canadian spending in the first half of the year should result in sequentially softer revenues in the first and second quarters of 2005.

     In 2004, 2003 and 2002, revenues outside North America were 58.4%, 57.7% and 59.9% of total revenues, respectively. In 2005, we expect revenues outside North America to continue to be between 55% and 60% of total revenues, and we expect these revenues to increase 7% to 9% in 2005 compared with 2004, continuing the multi–year trend of modest growth in customer spending. Spending on large projects by NOCs will reflect established seasonality trends, resulting in softer revenues in the first half of the year and stronger revenues in the second half. In addition, customer spending should be affected by weather–related reductions in the North Sea in the first and second quarters of 2005. The Middle East, Africa and Latin America are expected to grow modestly in 2005 compared with 2004. Our expectations for spending and revenue growth could decrease if average prices fall below $35/Bbl for oil or $5/mmBtu for natural gas or if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In 2004, WesternGeco contributed $34.5 million of equity in income of affiliates compared with equity in loss of affiliates of $9.9 million in 2003, which excludes $135.7 million related to our portion of certain restructuring and impairment charges taken by WesternGeco in the third quarter of 2003, which we recorded in “Equity in income (loss) of affiliates” in our consolidated statement of operations. We expect the trend of improving operating results for WesternGeco to continue throughout 2005; however, based on the historical trend of operating losses and weakness in the seismic industry in prior years, there is uncertainty regarding the future operating results of WesternGeco. Information regarding WesternGeco’s profitability in 2005 is based on information that WesternGeco has provided to us. Should this information not be accurate, our forecasts for profitability could be impacted, either positively or negatively.

     In 2005, we modified our stock award program to provide a combination of both restricted stock and stock option awards. Restricted stock awards and stock option awards were granted in January and stock option awards may also be granted in July. As required under the current accounting rules, awards of restricted stock are expensed over the vesting period based on their fair value when granted. We will begin expensing the fair value of stock option awards and stock issued under the employee stock purchase plan in July 2005, when we adopt the revised Statement of Financial Accounting Standards No. 123, Share–Based Payment (“SFAS No. 123R”). We are currently in the process of evaluating different option pricing models and the impact of SFAS No. 123R on our consolidated financial statements. If we were to adopt SFAS No. 123R in July 2005 using a prospective application, we expect that income from continuing operations per diluted share will be reduced by approximately $0.03 for 2005. For further information, see Note 1 of the Notes to the Consolidated Financial Statements in Item 8 herein.

     Based on the above forecasts, we believe that income from continuing operations per diluted share in 2005 will be in the range of $1.80 to $1.95, which includes the impact of expensing restricted stock awards but excludes the impact of expensing stock option awards and stock issued under the employee stock purchase plan. Significant price increases or significantly better than expected results from WesternGeco could cause earnings per share to reach the upper end of this range. Conversely, significant price decreases or significantly worse than expected results at WesternGeco could result in earnings per share being at or below the bottom of this range. 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 price improvement, without pricing discipline throughout the industry as a whole, meaningful improvements in our prices are not likely to be realized. Additionally, significant changes in drilling activity outside our expectations, as well as changes in expected costs of raw materials, could impact operating results positively or negatively.

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     We do business in approximately 90 countries including over one–half of the 35 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2004. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt Practices Act (the “FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulation, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. In addition, U.S. government agencies and authorities are conducting investigations into allegations of potential violations of laws. We anticipate that the devotion of significant resources to compliance related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. Compliance related issues could limit our ability to do business in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with laws and regulations and our Business Code of Conduct.

Risk Factors Related to Our Business

     Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending and profitability, are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which are affected by the following risk factors and the timing of any of these risk factors:

•	Oil and gas market conditions – the level of petroleum industry E&P expenditures; drilling rig and oil and natural gas industry manpower and equipment availability; the price of, and the demand for, crude oil and natural gas; drilling activity; risks from operating hazards; seasonal and other weather conditions that affect the demand for energy; severe weather conditions, such as hurricanes, that affect exploration and production activities; OPEC policy and the adherence by OPEC nations to their OPEC production quotas; war, military action, terrorist activities or extended period of international conflict, particularly involving the U.S., Middle East or other major petroleum–producing or consuming regions; civil unrest or security conditions where we operate; expropriation of assets by governmental action.
•	Pricing, market share and contract terms – our ability to implement and affect price increases for our products and services; receipt of license fees; the effect of the level and sources of our profitability on our tax rate; the ability of our competitors to capture market share; our ability to retain or increase our market share; changes in our strategic direction; our ability to negotiate acceptable terms and conditions with our customers, especially NOCs; our ability to manage warranty claims and improve performance and quality; our ability to effectively manage our commercial agents.
•	Costs and availability of resources – our ability to manage the rising costs and availability of sufficient raw materials and components (especially steel alloys, copper and chemicals); our ability to recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; manufacturing capacity and subcontracting capacity at forecasted costs to meet our revenue goals; the availability of essential electronic components used in our products; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; potential impairment of long–lived assets; the accuracy of our estimates regarding our capital spending requirements; unanticipated changes in the levels of our capital expenditures; the need to replace any unanticipated losses in capital assets; the development of technology by us or our competitors that lowers overall finding and development costs; labor–related actions, including strikes, slowdowns and facility occupations.
•	Litigation and changes in laws or regulatory conditions – the potential for unexpected litigation or proceedings; the legislative, regulatory and business environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; new laws, regulations and policies that could have a significant impact on the future operations and conduct of all businesses; changes in export control laws or exchange control laws; additional restrictions on doing business in countries subject to sanctions: changes in laws in Russia or other countries identified by management for immediate focus; changes in accounting standards; changes in tax laws or tax rates in the jurisdictions in which we operate; resolution of audits by various tax authorities; ability to fully utilize our tax loss carryforwards and tax credits.
•	Economic conditions – worldwide economic growth; foreign currency exchange fluctuations and changes in the capital markets in international locations where we operate; the condition of the capital and equity markets in general; our ability to estimate the size of and changes in the worldwide oil and natural gas industry.

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•

Environmental matters – unexpected, adverse outcomes or material increases in liability with respect to environmental remediation sites where we have been named as a potentially responsible party; the discovery of new environmental remediation sites; changes in environmental regulations; the discharge of hazardous materials or hydrocarbons into the environment. See also the “Environmental Matters” section in Item 1 contained herein for further information.

     For additional risk factors and cautions regarding forward–looking statements, see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Forward–Looking Statements” sections contained herein. This list of risk factors is not intended to be all inclusive.

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 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 our financial condition and 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 accounting methodology used to establish the critical accounting estimates discussed below. We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimation but are not deemed critical as defined above.

Allowance for Doubtful Accounts

     The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2004 and 2003, reserves for doubtful accounts totaled $50.5 million, or 3.6%, and $61.8 million, or 5.1%, of total accounts receivable before reserves, respectively. We believe that our reserve for doubtful accounts is adequate to cover anticipated 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 this reserve would have had a pre–tax impact of approximately $2.5 million in 2004.

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 or 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, 2004 and 2003, inventory reserves totaled $221.1 million, or 17.6%, and $232.5 million, or 18.7%, of gross inventory, respectively. We believe that our reserves are adequate to cover anticipated losses under current conditions. Significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent difference in this reserve would have had a pre–tax impact of approximately $11.1 million in 2004.

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

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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.

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 potentially through the courts. We believe that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors which 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. While we have provided for the taxes that we believe will ultimately be payable as a result of these assessments, the aggregate assessments are approximately $34.0 million in excess of the taxes provided for in our consolidated financial statements.

     In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we consider it probable that the taxes ultimately payable will exceed those amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies .

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. Other less critical assumptions used in determining benefit obligations and plan expenses, such as demographic factors

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like retirement age, mortality and turnover, are also evaluated periodically and are updated accordingly to reflect our actual experience.

     The discount rate enables us to state expected future cash flows at a present value on the measurement date. A lower discount rate increases the present value of benefit obligations and increases plan expenses. We used a discount rate of 6.25% in 2004, 6.75% in 2003 and 7.00% in 2002 to determine plan expenses. A 75 basis point reduction in the discount rate would have increased plan expenses in 2004 by $6.2 million.

     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 that rates of return on our plan investments were 8.50% in 2004 and 2003 and 9.00% in 2002. A 50 basis point decrease in the expected rate of return on assets of our principal plans would have increased plan expenses in 2004 by $1.8 million.

DISCONTINUED OPERATIONS

     In September 2004, we completed the sale of Baker Hughes Mining Tools (“BHMT”), a product line group within the Oilfield segment that manufactured rotary drill bits used in the mining industry, for $31.5 million. We recorded a gain on the sale of $0.2 million, net of tax of $3.6 million, which consisted of a gain on the disposal of $6.8 million offset by a loss of $6.6 million related to the recognition of the cumulative foreign currency translation adjustments into earnings.

     In October 2003, we signed a definitive agreement for the sale of BIRD Machine (“BIRD”), the remaining division of the former Process segment, and recorded charges totaling $37.4 million, net of tax of $10.9 million, which consisted of a loss of $13.5 million on the write–down of BIRD to fair value, $6.2 million of severance and warranty accruals and a loss of $17.7 million related to the recognition of cumulative foreign currency translation adjustments into earnings. In January 2004, we completed the sale of BIRD and recorded an additional loss on the sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price, and retained certain accounts receivable, inventories and other assets. During the second quarter of 2004, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments. The adjustments were the result of changes in the value of assets sold to and liabilities assumed by the buyer between the date the initial sales price was negotiated and the closing of the sale.

     In December 2002, we entered into exclusive negotiations for the sale of our interest in our oil producing operations in West Africa for $32.0 million in proceeds. The transaction was effective as of January 1, 2003, and resulted in a gain on the sale of $4.1 million, net of a tax benefit of $0.2 million. We received $10.0 million as a deposit in 2002 and the remaining $22.0 million in April 2003.

     In November 2002, we sold EIMCO Process Equipment (“EIMCO”), a division of the former Process segment, and recorded a loss on the disposal of $22.3 million, net of tax of $1.2 million, which consisted of a loss of $2.3 million on the write–down to fair value and a loss of $20.0 million related to the recognition of cumulative foreign currency translation adjustments into earnings. We received total proceeds of $48.9 million, of which $4.9 million was held in escrow pending completion of final adjustments to the purchase price. In 2003, all purchase price adjustments were completed, resulting in the release of the escrow balance, of which we received $2.0 million and $2.9 million was returned to the buyer. In 2003, we also recorded an additional loss on the sale due to purchase price adjustments of $2.5 million, net of tax of $1.3 million.

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

RESULTS OF OPERATIONS

     The discussions below relating to significant line items 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.

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     The table below details certain consolidated statement of operations data and their percentage of revenues for 2004, 2003 and 2002, respectively.

Revenues

     Revenues for 2004 increased 16.2% compared with 2003, reflecting a 10.1% increase in the worldwide rig count. Revenues in North America, which accounted for 41.6% of total revenues, increased 14.4% compared with 2003. This increase reflects increased drilling activity in the U.S. and Canada, as evidenced by a 10.9% increase in the North American rig count, and $24.8 million related to intellectual property license fees, which is not expected to recur in the same magnitude in the future. Revenues outside North America, which accounted for 58.4% of total revenues, increased 17.5% compared with 2003. This increase reflects the improvement in international drilling activity, as evidenced by an 8.6% increase in the rig count outside North America, primarily in Latin America and Asia Pacific, partially offset by decreased drilling activity in the North Sea and Africa. During 2004, our revenue growth was primarily due to increases in activity and, to a lesser extent, pricing improvements.

     Revenues for 2003 increased 8.1% compared with 2002, reflecting a 19.1% increase in the worldwide rig count. Revenues in North America, which accounted for 42.3% of total revenues, increased 14.0% compared with 2002. This increase reflects increased drilling activity in the U.S. and Canada, as evidenced by a 28.4% increase in the North American rig count. Revenues outside North America, which accounted for 57.7% of total revenues, increased 4.1% compared with 2002. This increase reflects the improvement in international drilling activity, as evidenced by the 5.2% increase in the rig count outside North America, primarily in Latin America and the Middle East, partially offset by decreased drilling activity in the North Sea and Africa. During 2003, pricing was not a significant contributor to our revenue growth, as deterioration in prices for certain product lines at our INTEQ division were partially offset by pricing improvement realized from our other product lines.

Cost of Revenues

     Cost of revenues for 2004 increased 14.3% compared with 2003. Cost of revenues as a percentage of revenues was 71.6% and 72.7% for 2004 and 2003, respectively. The decrease in cost of revenues as a percentage of revenues is primarily related to limited pricing improvement in certain markets and product lines and improved cost control measures, including lower repair and maintenance costs at our INTEQ division, partially offset by increased material costs and higher employee bonus expense. 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. During 2004, our revenue increases came predominantly from outside North America and our margins on revenues generated outside North America are typically higher than margins generated in North America.

     Cost of revenues for 2003 increased 9.5% compared with 2002. Cost of revenues as a percentage of revenues was 72.7% and 71.8% for 2003 and 2002, respectively. The increase in cost of revenues as a percentage of revenues is primarily related to our INTEQ division. In 2003, INTEQ experienced the highest revenue growth of our divisions; however, margins deteriorated as they were impacted by increased downward pricing trends, increased repair and maintenance costs for newly developed downhole rental tools and other nonrecurring costs. A change in the geographic and product mix from the sale of our products and services also contributed to the increase in the cost of revenues as a percentage of revenues. During 2003, our revenue increases came predominantly from North America and our margins on revenues generated in North America are typically lower than margins generated outside of North America.

Selling, General and Administrative

     Selling, general and administrative (“SG&A”) expenses for 2004 increased 10.7% compared with 2003. This increase was primarily due to higher marketing and administrative expenses as a result of increased activity, including higher annual employee bonus expense, and increased costs related to our continued focus on compliance, including legal investigations and increased staffing in our legal, compliance and audit groups. The increase was also due to the implementation of programs and procedures as a result of the requirements of the Sarbanes–Oxley Act of 2002.

     SG&A expenses for 2003 increased 2.4% compared with 2002. This increase was primarily due to an $8.9 million increase in net costs related to corporate activities and an increase of approximately $17.0 million in costs related to our self insurance programs, offset by improvement in the impact of foreign currency exchange activity of $18.3 million.

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Reversal of Restructuring Charge

     In 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and we 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 subsequently sold in 2003 and we reversed the liability related to this contractual obligation.

Impairment of Investment in Affiliate

     In 2003, as a result of the continued weakness in the seismic industry, we evaluated the carrying value of our investment in WesternGeco and recorded an impairment loss of $45.3 million to write–down the investment to its fair value. The fair value was determined using a combination of a market capitalization and discounted cash flows approach. We were assisted in the determination of the fair value by a third party. Although not anticipated, further declines in the fair value of the investment in WesternGeco would result in additional impairments.

Equity in Income (Loss) of Affiliates

     Equity in income of affiliates was $36.3 million in 2004 compared with equity in loss of affiliates of $2.1 million in 2003, which excludes the $135.7 million related to our portion of the restructuring and impairment charge taken by WesternGeco in the third quarter of 2003. During 2003, the operating results of WesternGeco continued to be adversely affected by the weakness in the seismic industry and, as a result of this weakness, WesternGeco recorded certain impairment and restructuring charges of $452.0 million for impairment of its multiclient seismic library and rationalization of its marine seismic fleet.

     Operating results for WesternGeco are expected to continue to improve in 2005; however, based on the trend of operating losses and weakness in the seismic industry in prior years, there is uncertainty regarding the future operating performance of WesternGeco.

Interest Expense

     Interest expense for 2004 decreased $19.5 million compared with 2003 primarily due to lower total debt levels and the effect of the interest rate swap agreement entered into in April 2004. The lower total debt levels are the result of the repayment of $350.0 million of long–term debt in the second quarter of 2004, which decreased interest expense by $16.0 million in 2004 compared with 2003. Additionally, the interest rate swap agreement decreased interest expense by $4.1 million in 2004 compared with 2003.

     Interest expense for 2003 decreased $8.0 million compared with 2002 due to lower total debt levels, lower weighted average interest rates on our commercial paper and money market borrowings and increased amortization of deferred gains related to terminated interest rate swap agreements. The lower total debt levels are the result of the repayment of $100.0 million of long–term debt in February 2003. The approximate weighted average interest rate on our commercial paper and money market borrowings was 1.2% in 2003 compared with 1.8% for 2002. The amortization of deferred gains related to terminated interest rate swap agreements reduced interest expense by $9.9 million in 2003 compared with $6.0 million in 2002.

Income Taxes

     Our effective tax rates differ from the U.S. statutory income tax rate of 35% due to state income taxes, differing rates of tax on international operations and higher taxes within the WesternGeco venture.

     During 2003, we recognized an incremental effect of $36.3 million of additional taxes attributable to our portion of the operations of WesternGeco. Of this amount, $15.9 million related to the reduction in the carrying value of our equity investment in WesternGeco for which there was no tax benefit. The remaining $20.4 million arose from operations of the venture due to: (i) the venture being taxed in certain foreign jurisdictions based on a deemed profit basis, which is a percentage of revenues rather than profits and (ii) unbenefitted foreign losses of the venture, which are operating losses and impairment and restructuring charges in certain foreign jurisdictions where there was no current tax benefit and where a deferred tax asset was not recorded due to the uncertainty of realization. In 2002, the amount of additional taxes resulting from operations of the venture was $40.2 million.

     During 2003, a benefit of $3.3 million was recognized as the result of various refund claims filed in the U.S. During 2002, a $14.4 million benefit was recognized as the result of the settlement of an IRS examination related to our September 30, 1996 through September 30, 1998 tax years.

     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 potentially through the courts. We believe

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that 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 have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

Cumulative Effect of Accounting Change

     On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations . SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate can be made. The liability for the ARO is revised each subsequent period due to the passage of time and changes in estimates. The associated retirement costs are capitalized as part of the carrying amount of the long–lived asset and subsequently depreciated over the estimated useful life of the asset. The adoption of SFAS No. 143 in 2003 resulted in a charge of $5.6 million, net of tax of $2.8 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded ARO liabilities of $11.4 million primarily for anticipated costs of obligations associated with the future disposal of power source units at certain of our divisions and refurbishment costs associated with certain leased facilities in Europe and with a fleet of leased railcars and tanks.

     On January 1, 2002, we adopted SFAS No. 142, Goodwill and Other Intangible Assets . The adoption of SFAS No. 142 required us to cease amortizing goodwill and to perform a transitional impairment test of goodwill in each of our reporting units as of January 1, 2002. The reporting units were based on our organizational and reporting structure. Corporate and other assets and liabilities were allocated to the reporting units to the extent that they related to the operations of these reporting units. Valuations of the reporting units were performed by a third party. The goodwill in both the EIMCO and BIRD operating divisions of the former Process segment was determined to be impaired using a combination of a market value and discounted cash flows approach to estimate fair value. Accordingly, we recognized transitional impairment losses of $42.5 million, net of tax of $20.4 million, in 2002 as the cumulative effect of accounting change in the consolidated statement of operations.

LIQUIDITY AND CAPITAL RESOURCES

     Our objective in financing our business is to maintain adequate financial resources and access to additional liquidity. During 2004, cash flows from operations and short–term borrowings were the principal sources of funding. We anticipate that cash flows from operations will cover our liquidity needs in 2005. We also have a $500.0 million committed revolving credit facility that provides back–up liquidity in the event of an unanticipated significant demand on cash flows that could not be funded by operations or short–term borrowings. This facility expires in July 2006.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In 2004, we used cash for a variety of activities including working capital needs, payment of dividends, repayments of indebtedness 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:

     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 considered to be 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 have been steadily increasing over the last three years and we expect this trend to continue in 2005. We attribute the increases in our cash flows to successful management of working capital and increasing levels of income from continuing operations adjusted for noncash items.

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     Cash flows from operating activities of continuing operations increased $132.0 million in 2004 compared with 2003. This increase was primarily due to increased operating performance, which is directly related to our increased revenues. In addition, changes in working capital, primarily consisting of changes in accounts receivable, inventories, accounts payable and other current liabilities, provided $12.7 million less in cash flows during 2004 compared with 2003.

     The underlying drivers of the changes in working capital are as follows:

	•	An increase in accounts receivable used $175.3 million in cash in 2004 compared with using $13.9 million in cash in 2003. This was due to the increase in revenues and an increase in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately two days.
	•	A build up in inventory in anticipation of increased activity used $4.5 million in cash in 2004 compared with providing $20.9 million in cash in 2003. The build up in inventory was partially offset by our continued focus on improving the utilization of inventory on hand.
	•	An increase in accounts payable and other current liabilities provided $190.6 million in cash in 2004 compared with providing $16.5 million in cash in 2003. This was due to increased activity, increased employee compensation accruals, better management of our accounts payable and $45.3 million less in net income tax payments in 2004 compared with 2003.

     Our pension contributions in 2004 were approximately $110.0 million, an increase of approximately $82.0 million compared with 2003, due to our decision to improve the funded status of certain pension plans and to provide us with increased flexibility on the future funding of these pension plans.

     Cash flows from operating activities of continuing operations increased $31.5 million in 2003 compared with 2002 primarily due to increased operating performance attributable to our increased revenues. In addition, working capital decreased with the effect of increasing cash flows from operating activities.

     The underlying drivers of the changes in working capital are as follows:

	•	An increase in accounts receivable in 2003 used $13.9 million in cash compared with providing $86.4 million in cash in 2002. This was primarily due to the increase in revenues offset by a reduction in days sales outstanding of approximately two days.
	•	A decrease in inventory in 2003 provided $20.9 million in cash compared with providing $15.4 million in cash in 2002 as we increased our focus on improving the utilization of inventory on hand.
	•	An increase in accounts payable and other current liabilities in 2003 provided $16.5 million in cash compared with using $106.2 million in cash in 2002. This was due to increased activity, increased employee compensation accruals, better management of our accounts payable and increased accruals for our self insurance programs. Theses changes were partially offset by an increase in income tax payments of $59.8 million in 2003 compared with 2002.

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 $348.3 million, $404.3 million and $355.9 million for 2004, 2003 and 2002, respectively. The majority of these expenditures were for rental tools, including wireline, and machinery and equipment.

     In December 2004, we paid $1.0 million in cash for the remaining 60% interest in Luna Energy L.L.C. (“Luna”), a venture we entered into in 2002. During 2004, we also paid $5.6 million in settlement of the final purchase price related to an acquisition completed in a prior year and invested an additional $7.1 million in certain of our investments in affiliates.

     In 2003, we made two acquisitions having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. In addition, during 2003, we invested $38.1 million in affiliates, of which $30.1 million related to our 50% interest in the QuantX Wellbore Instrumentation venture, which is engaged in the permanent in–well monitoring market.

     In 2002, we made three acquisitions having an aggregate cash purchase price of $39.7 million, net of cash acquired. In addition, during 2002, we invested $16.5 million in Luna.

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     In 2004, we received $58.7 million in net proceeds from the sale of businesses and our interest in an affiliate. In January, we completed the sale of BIRD and received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price. During the second quarter, we made a net payment of $6.8 million to the buyer in settlement of the final purchase price adjustments. In February, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, and received proceeds of $35.8 million, of which $7.4 million is held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. A portion of the escrow will be released in May 2005, with the remainder released in February 2006. In September, we also completed the sale of BHMT and received proceeds of $31.5 million.

     In 2003, we completed the sale of our interest in an oil producing property in West Africa for $32.0 million in proceeds. We received a deposit of $10.0 million in 2002 and the remaining $22.0 million in 2003. During 2002, we also disposed of our EIMCO division for $48.9 million in proceeds. We received $44.0 million in proceeds in 2002, with the remainder of the sales price held in escrow pending completion of final adjustments of the purchase price. In 2003, all purchase price adjustments were completed, resulting in the release of the escrow balance. We received $2.0 million and $2.9 million was returned to the buyer.

     Proceeds from disposal of assets were $106.9 million, $66.8 million and $77.7 million for 2004, 2003 and 2002, 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 2004 was $12.2 million related to the sale of certain real estate properties held for sale.

Financing Activities

     We had net borrowings (repayments) of commercial paper and other short–term debt of $35.5 million, $11.2 million and $(162.4) million in 2004, 2003 and 2002, respectively. In 2004, we repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. In 2003, we repaid the $100.0 million 5.8% Notes due February 2003. These repayments were funded with cash on hand, cash flows from operations and the issuance of commercial paper.

     Total debt outstanding at December 31, 2004 was $1,162.3 million, a decrease of $322.1 million compared with December 31, 2003. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.23 at December 31, 2004 and 0.31 at December 31, 2003.

     At different times during 2003, we entered into three separate interest rate swap agreements, each for a notional amount of $325.0 million, associated with our 6.25% Notes due January 2009. These agreements had been designated and had qualified as fair value hedging instruments. Due to our outlook for interest rates, we terminated the three agreements and received payments totaling $26.9 million. Each of the three agreements was terminated prior to entering into a new agreement. The deferred gains are being amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matures in January 2009.

     During 2002, we terminated two interest rate swap agreements that had been entered into in prior years. These agreements had been designated and had qualified as fair value hedging instruments. Upon termination, we received proceeds of $4.8 million and $11.0 million. The deferred gain of $4.8 million was amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matured in June 2004. The deferred gain of $11.0 million is being amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matures in January 2009.

     We received proceeds of $115.9 million, $61.8 million and $38.3 million in 2004, 2003 and 2002, respectively, from the issuance of common stock through the exercise of stock options and our employee stock purchase plan.

     During 2002, we were authorized by our Board of Directors to repurchase up to $275.0 million of our common stock. During 2003, we repurchased 6.3 million shares at an average price of $28.78 per share, for a total of $181.4 million. During 2002, we repurchased 1.8 million shares at an average price of $27.52 per share, for a total of $49.1 million. Upon repurchase, the shares were retired. We did not repurchase any shares during 2004.

     We paid dividends of $153.6 million, $154.3 million and $154.9 million in 2004, 2003 and 2002, respectively.

Available Credit Facilities

     At December 31, 2004, we had $897.4 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2006. 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 0.50, limit the amount of subsidiary indebtedness and restrict the sale of significant assets, defined as 10% or more of total

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consolidated assets. At December 31, 2004, we were in compliance with all the facility covenants. There were no direct borrowings under the facility during the year ended December 31, 2004; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2004, we had no outstanding commercial paper or money market borrowings.

     If market conditions were to change and revenues were to be significantly reduced or operating costs were to increase, our cash flows and liquidity could be reduced. Additionally, it could cause the rating agencies to lower our credit rating. 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. Also, a downgrade in our credit ratings could limit or preclude our ability to issue commercial paper. Should this occur, we would seek alternative sources of funding, including borrowing under the facility.

Cash Requirements

     In 2005, 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 currently expect that 2005 capital expenditures will be between $440.0 million and $460.0 million, 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 2005, we expect to make interest payments of approximately $80.0 million to $90.0 million. This is based on our current expectations of debt levels during 2005.

     We have authorization remaining to repurchase up to $44.5 million in common stock. We may continue to repurchase our common stock in 2005 depending on the price of our common stock, our liquidity and other considerations. In 2005, we anticipate paying dividends of $0.46 per share of common stock. However, our Board of Directors is free to change the dividend policy at any time.

     During 2005, we estimate that we will contribute approximately $12.0 million to $19.0 million to our pension plans and make benefit payments related to postretirement welfare plans of approximately $16.3 million. We also estimate that we will contribute approximately $70.0 million to $80.0 million to our defined contribution plans.

     We anticipate making income tax payments of approximately $230.0 million to $260.0 million in 2005.

     We do not believe that 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 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 2004 are not indicative of what we can expect in the future.

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Contractual Obligations

     In the table below, we set forth our enforceable and legally binding obligations as of December 31, 2004. Some of the figures we include 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 enforceable and legally binding obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

(2) Amounts represent the expected cash payments for interest on our fixed rate long–term debt.

(3) We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the lease. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.

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

(5) Amounts represent other long–term liabilities, including the current portion, reflected in the consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions, payments for various postretirement welfare benefit plans and postemployment benefit plans and payments for deferred taxes and other tax liabilities, as such amounts have not been determined beyond 2005.

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 $312.3 million at December 31, 2004. In addition, at December 31, 2004, we have guaranteed debt and other obligations of third parties with a maximum potential exposure of $7.4 million. None of these off–balance sheet arrangements either has, or is likely to have, a material effect on our current or future financial condition, results of operations, liquidity or capital resources.

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

NEW ACCOUNTING STANDARDS

     In January 2003, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 46 (“FIN 46”), Consolidation of Variable Interest Entities . An entity is subject to the consolidation rules of FIN 46 and is referred to as a variable interest entity (“VIE”) if the entity’s equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its operations without additional financial support. In December 2003, the FASB issued modifications to FIN 46 (“FIN 46R”), resulting in multiple effective dates based on the nature as well as the creation date of a VIE. The adoption of FIN 46 and FIN 46R in 2004 had no impact on our consolidated financial statements.

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     In May 2004, the FASB issued FASB Staff Position No. 106–2 (“FSP 106–2”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 , which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 for employers that sponsor postretirement health care plans that provide prescription drug benefits. We adopted the provisions of FSP 106–2 in the third quarter of 2004, resulting in a reduction in our accumulated postretirement benefit obligation of $18.8 million. We recognized a reduction in our net periodic postretirement benefit costs of $2.0 million for 2004 as a result of the adoption of FSP 106–2.

     In November 2004, the FASB issued SFAS No. 151, Inventory Costs – an Amendment of ARB No. 43, Chapter 4 , which amends the guidance in ARB No. 43 to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. SFAS No. 151 requires that these items be recognized as current period charges. In addition, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We are currently evaluating the provisions of SFAS No. 151 and will adopt SFAS No. 151 on January 1, 2006.

     In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29 , to address the measurement of exchanges of nonmonetary assets. SFAS No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is effective for nonmonetary exchanges occurring after June 30, 2005. We will adopt SFAS No. 153 on July 1, 2005.

     In December 2004, the FASB revised SFAS No. 123, Share–Based Payment (“SFAS No. 123R”). SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock–Based Compensation , and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees . SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant–date fair value of the award. That cost will be recognized over the period in which an employee is required to provide service in exchange for the award. SFAS No. 123R also requires a public entity to initially measure the cost of employee services rendered in exchange for an award of liability instruments at its current fair value. The fair value of that award is to be remeasured subsequently at each reporting date through the settlement date. Changes in the fair value during the required service period are to be recognized as compensation cost over that period. We are currently in the process of evaluating different option pricing models and the impact of SFAS No. 123R on our consolidated financial statements. We will adopt SFAS No. 123R on July 1, 2005.

     In December 2004, the FASB issued FASB Staff Position No. 109–1 (“FSP 109–1”), Application of FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 , which provides guidance on the recently enacted American Jobs Creation Act of 2004 (the “Act”). The Act provides a tax deduction for income from qualified domestic production activities. FSP 109–1 provides for the treatment of the deduction as a special deduction as described in SFAS No. 109. As such, the deduction will have no effect on existing deferred tax assets and liabilities. The impact of the deduction is to be reported in the period in which the deduction is claimed on our U.S. tax return. We do not expect that this deduction will have a material impact on our effective tax rate in future years. FSP 109–1 is effective prospectively as of January 1, 2005.

     In December 2004, the FASB issued FASB Staff Position No. 109–2 (“FSP 109–2”), Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109–2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have not yet decided on whether, and to what extent, we might elect to repatriate foreign earnings under the provisions in the Act. Any such repatriation under the Act must occur by December 31, 2005. Accordingly, our consolidated financial statements do not reflect a provision for taxes related to this election. The maximum amount we could elect to repatriate is $500 million as prescribed in the Act. Our evaluation of the effect of the election is expected to be completed by the end of the second quarter of 2005.

RELATED PARTY TRANSACTIONS

     In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true–up payment will be made by either of the parties based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic data libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party will be required to make as a result of this adjustment is $100.0 million. We currently estimate that Schlumberger will make a payment to us in the range

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of $9.0 million to $11.5 million, pending final determination of the adjustment. When received, this payment will be recorded as a reduction to the carrying value of our investment in WesternGeco. This payment will be taxable when paid and the tax effect will be recorded as current income tax expense.

     In November 2000, we also entered into an agreement with WesternGeco whereby WesternGeco subleased a facility from us for a period of ten years at then current market rates. During 2004, 2003 and 2002, we received payments of $5.5 million, $5.0 million and $5.5 million, respectively, from WesternGeco related to this lease.

     On or after December 1, 2005, either party to the WesternGeco Master Formation Agreement may offer to sell their entire interest in the venture to the other party at a cash purchase price per percentage interest specified in an offer notice. If the offer to sell is not accepted, the offering party will be obligated to purchase the entire interest of the other party at the same price per percentage interest as the price specified in the offer notice. We cannot predict when, or if, we or Schlumberger may exercise this right.

     At December 31, 2004 and 2003, net accounts (payable) receivable from affiliates totaled $(1.1) million and $0.7 million, respectively. 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 of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward–looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “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. 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, 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.

     These forecasts may be substantially different from actual results, which are affected by those risk factors and the timing of any of those risk factors identified in the “Environmental Matters” section in Item 1 herein and the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and “Risk Factors Related to Our Business” sections contained herein.

     At December 31, 2004 and 2003, we had fixed rate debt aggregating $1,075.2 million and $1,425.6 million, respectively. 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, 2004 and 2003 (dollar amounts in millions).

INTEREST RATE SWAP AGREEMENTS

     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. Under this agreement we receive interest at a fixed rate of 6.25% and pay interest at a floating rate of six–month LIBOR plus a spread of 2.741%. The interest rate swap agreement has been designated and qualifies as a fair value hedging instrument. The interest rate swap agreement is fully effective, resulting in no gain or loss recorded in the consolidated statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $2.3 million liability at December 31, 2004, based on quoted market prices for contracts with similar terms and maturity dates.

     At different times during 2003, we entered into three separate interest rate swap agreements, each for a notional amount of $325.0 million, associated with our 6.25% Notes due January 2009. These agreements had been designated and had qualified as fair value hedging instruments. Due to our outlook for interest rates, we terminated the three agreements and received payments totaling $26.9 million. Each of the three agreements was terminated prior to entering into a new agreement. The deferred gains are being amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matures in January 2009.

     During 2002, we terminated two interest rate swap agreements that had been entered into in prior years. These agreements had been designated and had qualified as fair value hedging instruments. Upon termination, we received proceeds of $4.8 million and $11.0 million. The deferred gain of $4.8 million was amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matured in June 2004. The deferred gain of $11.0 million is being amortized as a reduction of interest expense over the remaining life of the underlying debt security, which matures in January 2009.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

     We conduct operations around the world in a number of different currencies. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes 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.

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     At December 31, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Norwegian Krone, the 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, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $0.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

     At December 31, 2004, we had also entered into several foreign currency forward contracts with notional amounts aggregating $122.4 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling and the Canadian Dollar. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. The funding of such imbalances is supported by short–term intercompany borrowing commitments that have definitive amounts and funding dates. All fundings are scheduled to take place on or before December 31, 2005. These foreign currency forward contracts were designated as cash flow hedging instruments and are fully effective. Based on quoted market prices as of December 31, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $0.1 million to adjust these foreign currency forward contracts to their fair market value. The loss is recorded in other comprehensive income in the consolidated balance sheet.

     At December 31, 2003, we had entered into several foreign currency forward contracts with notional amounts aggregating $62.5 million to hedge exposure to currency fluctuations in various foreign currencies, including the British Pound Sterling, the Norwegian Krone, the Euro, the Brazilian Real and the Argentine Peso. These contracts are designated and qualify as fair value hedging instruments. Based on quoted market prices as of December 31, 2003 for contracts with similar terms and maturity dates, we recorded a gain of $1.5 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated foreign exchange losses resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

     The counterparties to the 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 rate differential.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as such term is defined in Exchange Act Rules 13a–15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our control environment is the foundation for our system of internal control and is embodied in our Business Code of Conduct, which sets the tone of our company and includes our Core Values of Integrity, Teamwork, Performance and Learning. Included in our system of internal control are written policies, an organizational structure providing division of responsibilities, the selection and training of qualified personnel and a program of financial and operations reviews by a professional staff of corporate 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 underlying transactions, including the acquisition and disposition of assets; (ii) provide reasonable assurance that our assets are safeguarded and transactions are executed in accordance with management’s and our directors’ authorization and are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

     Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting. Our evaluation was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     Based on our evaluation under the framework in Internal Control – Integrated Framework , our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2004. 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Baker Hughes Incorporated
Houston, Texas

     We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Baker Hughes Incorporated and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

     A 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, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of December 31, 2004 and for the year then ended, and the financial statement schedule II; and our report dated February 24, 2005 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 24, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Baker Hughes Incorporated
Houston, Texas

     We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule II, valuation and qualifying accounts. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

     As described in Note 1 to the consolidated financial statements: effective as of January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, which established new accounting and reporting standards for asset retirement obligations; and effective as of January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, which established new accounting and reporting standards for the recording, amortization and impairment of goodwill and other intangibles.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 24, 2005

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See Notes to Consolidated Financial Statements

44

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

See Notes to Consolidated Financial Statements

45

See Notes to Consolidated Financial Statements

46

See Notes to Consolidated Financial Statements

47

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 wellbore–related 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 (“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 and when collectibility is reasonably assured. Provisions for estimated warranty returns or similar types of items are made at the time the related revenue is recognized. Revenue for services 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.

Inventories

     Inventories are stated at the lower of cost or market. Cost is determined using the first–in, first–out (“FIFO”) method or the average cost method, which approximates FIFO, and includes the cost of materials, labor and manufacturing overhead.

Property and Depreciation

     Property is stated at cost less accumulated depreciation, which is generally provided by using the straight–line method over the estimated useful lives of the individual assets. We manufacture a substantial portion of our rental tools and equipment and the cost of these items, which includes direct and indirect manufacturing costs, are capitalized and carried in inventory until the tool is completed. Once the tool has been completed, the cost of the tool is reflected in capital expenditures and the tool is classified as rental tools and equipment in property. Significant improvements and betterments are capitalized if they extend the useful life of the asset.

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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

     We had an interest in an oil producing property in West Africa that was sold effective January 2003 and is classified as a discontinued operation. We used the full–cost method of accounting for this property. Under this method, we capitalized all acquisition, exploration and development costs incurred for the purpose of finding oil reserves. In accordance with full cost accounting rules, we performed ceiling tests on the carrying value of our oil properties. During 2002, there was no ceiling test charge recorded. Depreciation, depletion and amortization of oil properties were computed using the unit–of–production method based upon production and estimates of proved reserves and totaled $16.6 million in 2002. No costs were excluded from the full cost amortization pool. At December 31, 2002, our only cost center related to these properties was in West Africa.

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 flows analysis, with the carrying value of the related assets.

     We perform an annual impairment test of goodwill as of October 1, or more frequently if circumstances indicate that impairment may exist. 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 flows approach.

Income Taxes

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

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

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

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

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Baker Hughes Incorporated
Notes to Consolidated Financial Statements (continued)

We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

Product Warranties

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

Environmental Matters

     Remediation costs are accrued based on estimates of probable environmental exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based on internal evaluations and are not discounted. Such accruals are recorded when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. As additional or more accurate information becomes available, we adjust such accruals 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

     The majority 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 foreign receivables or payables, are included in selling, general and administrative (“SG&A”) expense in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and losses resulting from balance sheet translation of foreign operations are also included in SG&A expense in the consolidated statements of operations as incurred. We recorded net foreign currency transaction and translation gains (losses) of $4.0 million, $1.5 million and $(16.8) million in 2004, 2003 and 2002, respectively.

Derivative Financial Instruments

     We monitor our exposure to various business risks including commodity price, foreign currency exchange rate and interest rate risks 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 use interest rate swaps to manage interest rate risk.

     At the inception of any new derivative, we designate the derivative as a cash flow hedge or fair value hedge. 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.

Stock–Based Compensation

     As allowed under Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock–Based Compensation , we have elected to account for our stock–based compensation using the intrinsic value method of accounting in accordance with Accounting Principles Board Opinion No. 25 (“APB No. 25”), Accounting for Stock Issued to Employees . Under this method, compensation expense is to be recognized for the difference between the quoted market price of the stock at the measurement date less the amount, if any, the employee is required to pay for the stock. Our reported net income does not include any compensation expense associated with stock option awards because the exercise prices of our stock option awards equal the market prices of the underlying stock when granted. Our reported net income does include compensation expense associated with restricted stock awards.

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