UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10–K

[X] þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[  ] oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Numberfile number 1–9397

Baker Hughes Incorporated

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PART I

ITEM 1. BUSINESS

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

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

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

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

     We have adopted a Business Code of Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also required our principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct and Code of Ethical Conduct CertificationCertifications are available on the Investor Relations section of our website at www.bakerhughes.com.www.bakerhughes.com. We intend to promptly disclose on our website information about any waiver of these codes with respect to our executive officers and directors. Our Corporate Governance Guidelines and the charters of our Audit/Ethics Committee, GovernanceCompensation Committee, Executive Committee, Finance Committee Executiveand Governance Committee and Compensation Committeeare also are available on the Investor Relations section of our website at www.bakerhughes.com. In addition, a copy of our Business Code of Conduct, Code of Ethical Conduct Certification, Corporate Governance Guidelines and the charters of the Committees referenced above are available in print at no cost to any stockholder who requests them by writing or telephoning us at the following address or telephone number:

Baker Hughes Incorporated
3900 Essex Lane, Suite 1200
Houston, TX 77027
Attention: Investor Relations
Telephone: (713) 439–8039

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

     We have sixseven operating divisions – Baker Atlas, Baker Hughes Drilling Fluids, Baker Oil Tools, Baker Petrolite, Centrilift, Hughes Christensen and INTEQ – that we have been aggregated to compriseinto the Oilfield segment because they have similar economic characteristics and because the long–term financial performance of these divisions is affected by similar economic conditions. These operating divisions manufacture and sell products and provide services used in the oil and natural gas industry, including drilling, formation evaluation, completion and production of oil and natural gas wells andwells. They operate in reservoir measurement and evaluation. The principalthe same markets, which include all of the major oil and natural gas producing regions of the world, includingworld: North America, South America, Europe, Africa, the Middle East and the Far East. The Oilfield segment also includes our 30% interest in WesternGeco, a seismic venture between the Company andwe entered into with Schlumberger Limited (“Schlumberger”), as well as other similar businesses.investments in affiliates.

     For additional industry segment information for the three years ended December 31, 2003,2004, see Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.

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Baker Atlas

     Baker Atlas is a leading provider of formation evaluation and perforatingwireline 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) or during. 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 (production logging).

Perforating Services.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 perforatingwireline completion and production services. Specific opportunities for competitive differentiation include:

	•		data acquisition efficiency,
	•		the sophistication and accuracy of measurements, and
	•		the ability to interpret the information gathered to quantify the hydrocarbons producible from the formation.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”) and, Precision Drilling Corporation.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.

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	•		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 productiontwo or more zones to be produced from more than one zone in a conventional verticalsingle well, fromusing multiple lateral zones, or even from multiple reservoirs in a field.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,” versushole” as opposed to conventional tools which can only be set inside casing. Thru–tubing inflatables enable remedial operations in liveproducing 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”) and, BJ Services Company and in workovers, itsvarious other competitors. Its primary competitors in workover are Halliburton, Schlumberger, Weatherford and Weatherford.various other competitors. Its major competitors in fishing are Smith International, Inc. (��(“Smith”), Weatherford and Weatherford.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. The division’sIts products provide measurable increases in productivity, increases,decreases in operating and maintenance cost reductions and solutions to environmental problems. Examples of specialty oilfield chemical programs include:

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	•		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. Especially susceptible to hydrates are subseaSubsea wells and flowlines, particularly in deepwater environments.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 solid hydrocarbons in the produced fluids to crystallize and deposit on the walls of the well’s tubing, flow lines and surface equipment. These deposits are commonly referred to as paraffin. Baker Petrolite offers solvents that remove the deposits, as well as inhibitors that prevent new deposits from forming.
	•		Scale inhibitors – Unlike paraffin deposits that originate from organic material in the produced hydrocarbons, scale deposits come from mineral–based contaminants in water that are produced from the formation as the water undergoes changes in temperature or pressure. Similar to paraffin, scale deposits can clog the production system. Treatments prevent and remove deposits in production systems.
	•		Corrosion inhibitors – Another problem caused by water mixed with downhole hydrocarbons is corrosion of the well’s tubulars and other production equipment. Corrosion can also be caused by dissolved hydrogen sulfide (“H2S”) gas which reacts with the iron in tubulars, valves and other system equipment. The H2S eats away at the iron source,equipment, potentially causing failures and leaks. Additionally, the reaction creates iron sulfide which can impair treating systems and cause blockages. Baker Petrolite offers a variety of corrosion inhibitors and H2S scavengers.

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•

Emulsion breakers – While waterWater and oil typically do not mix, but water present in the reservoir and co–produced with oil can often become emulsified, or mixed, causing many 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. OpportunitiesSpecific opportunities for competitive differentiation based on chemical system performance 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 Champion Servo.various other competitors.

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

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Centrilift

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

     Electrical Submersible Pump Systems.ESPs lift 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.

     Opportunities6

     Specific opportunities for competitive differentiation for both ESP and PCP systems include:

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

     Centrilift’s primary competitors in the ESP market are Schlumberger, and John Wood Group PLC and various other competitors and in the PCP market are Weatherford, and 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, prices.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 bit products,bits, primarily Tricone® roller cone bits and fixedfixed–cutter polycrystalline diamond compact (“PDC”) cutter bits, to the worldwide oil and natural gas mining and geothermal industries.industry. The primary objective of a drill bitsbit is to createdrill 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. Tri–cone®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 Tri–cone®Tricone® bits. A rental market is developinghas 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, and Grant Prideco, Inc. and in the mining and geothermal bit markets are Sandvik Smith AB and Varel International, Inc.

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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. In addition, INTEQ is a major supplier of drilling fluids.

     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 that it is oriented due toby orienting its angled housing, gradually guiding the wellbore through an arc.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.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 rocksformation 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 allowenable “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.

Drilling and Completion Fluids.INTEQ is also a major provider of drilling fluids (also called “mud”) and completion fluids (also called “brines”). Drilling fluid is an important component of the drilling process. It is pumped from the surface through the drill string, exiting nozzles in the drill bit and traveling back up the wellbore where it is 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

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contain barite or bentonite to give them weight which allows the fluid to hold the wellbore open and stabilize it. Additionally, the fluid controls downhole pressures and seals porous sections of the wellbore. To insure maximum efficiency and wellbore stability, drilling fluid is often customized by the wellsite engineer. For drilling through the reservoir itself, INTEQ’s drill–in or completion fluids possess properties that minimize formation damage.

     As part of INTEQ’s mud logging services, engineers monitor the interaction between the drilling fluid and the formation, 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.

     INTEQ also provides equipment and services to separate the drill cuttings from the drilling fluids and re–inject the processed cuttings into a specially prepared well, or transport and dispose of the cuttings by other means.

     In fluids, the main driver of customer purchasing decisions is cost efficiency. Performance–based opportunities for competitive differentiation include:

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

     INTEQ’s primary competitors in drilling and evaluation services are Halliburton, and Schlumberger and in drilling and completion fluids are Halliburton and M–I, LLC.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 provider of seismic data acquisitionventure in which we own 30% and processingSchlumberger owns 70%. WesternGeco provides comprehensive worldwide reservoir imaging, monitoring and development services, to assist oil and natural gas companies in evaluating the producing potential of sedimentary basins and in locating productive hydrocarbon zones. Seismic data is acquired by producing sound waves which move down through the earth and are recorded by audio instruments. The recordings are then analyzed to determine the characteristicswith one of the geologic formations through whichmost extensive seismic crews and data processing centers in the sound waves movedindustry, as well as one of the world’s largest multiclient seismic libraries. Services range from 3D and the extent that oil and natural gas may be trapped in or moving through those formations. This analysis is known as a seismic survey. WesternGeco maintains a library of such seismic surveys.

     WesternGeco conductstime–lapse (4D) seismic surveys on land and, with its marine seismic fleet, in deep water and across shallow–water transition zones worldwide. These seismic surveys encompass high–resolution, two–dimensional and three–dimensionalto 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 targets. WesternGeco also conducts time–lapse, four–dimensionalthrough enhanced recovery. Q* single–sensor hardware and software are setting a new quality and capability standard for seismic surveyssolutions.

     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 monitoring reservoir fluid movement over time. Seismic information can reduce field development and production costs by reducing turnaround time, lowering drilling risks and minimizingeven the number of wells necessary to explore and develop reservoirs.most complex processing projects. WesternGeco’s major competitors in providing these services are Compagnie Generale de Geophysique, Veritas DGC, Inc. and Petroleum Geo–ServicesGeo-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. In certain areas outside the United States, we utilize licensees, sales representatives, agents and distributors.

     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;quality, availability and reliability;reliability, health, safety and environmental standards;standards, technical proficiency and price.

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     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 8090 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,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 the Company,us, division and corporate management routinely evaluate these risks periodically 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, 2003,2004, 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 raw 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 hydrocarbon–based chemical feed stocks. All of these materials are available from numerous sources.sources and could be subject to rising costs. We have not experienced any significant shortages of rawthese materials and normally do not carry inventories of such raw 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–long term.

OTHER DEVELOPMENTS

     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 sale of $4.1 million, net of a tax benefit of $0.2 million, recorded in the first quarter of 2003. We received $10.0 million as a deposit in 2002 and the remaining $22.0 million in April 2003.

     In the third quarter of 2003, our Board of Directors approved and management initiated a plan to sell BIRD, the remaining operating division of our former Process segment.     In October 2003, we entered intosigned a definitive agreement for the sale of BIRD. Accordingly, we classified BIRD as a discontinued operationMachine (“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–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. The sale closed inIn January 2004, we completed the sale of BIRD and werecorded an additional loss on the sale of $0.5 million with no tax benefit. We received proceeds of $5.6 million in proceeds, which iswere subject to adjustment pending final completion ofpost–closing adjustments to the purchase price. Weprice, 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 and received proceeds offor $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 do not believerecognized a gain on the transaction is materialsale 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 our financial condition or resultsthe recognition of operations.the cumulative foreign currency translation adjustments into earnings.

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EMPLOYEES

     At December 31, 2003,2004, we had approximately 26,65026,900 employees, as compared with approximately 26,500 employees at December 31, 2002.2003. Approximately 2,4002,300 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 March 3, 2004,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 whichthat are subject to domestic (including U. S.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 committed to the health and safety of people, protection of the environment and compliance with laws, regulations and our policies.

     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 we no longer actively useused 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 known environmental remediationprobable exposure using currently available facts, existing environmental permits, and technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates of costs 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 costs,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 the then current 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 by us to the total volume of waste disposed at the site. With the joint and several liability imposed under Superfund, a PRP may be required to pay more than its proportional share of such costs.

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     During the year ended December 31, 2003, we spent approximately $21.8 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”). In 2004, we expect to spend approximately $24.0 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 made adequate reserves for those compliance expenditures or the cost to us for that compliance is not expected to be material to our financial condition or results of operations.

     During the year ended December 31, 2003, we incurred approximately $3.6 million in capital expenditures for environmental control equipment and we estimate that we will incur approximately $4.0 million during 2004.     We believe that these capital expenditures for environmental control equipment will not have a material adverse effect upon our financial condition or results of operations because the aggregate amount of these expenditures is not expected to be material.

     We and several of our subsidiaries and divisions have been identified as PRPs at various Superfund sites discussed below. The United States Environmental Protection Agency (the “EPA”) and appropriate state agencies are supervisingsupervise investigative and cleanup activities at these sites. ForAt December 31, 2004, we have accrued $3.6 million of remediation costs related to the sites detailed below, we estimate remediation costs of approximately $6.1 million, of which we had spent $1.8 million as of December 31, 2003.below. When used in the descriptions of the sites below, the wordde minimismeansrefers to the smallest PRPs, whose contribution rate is usually less than a 1% contribution rate..

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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. Sheridan Site Trust officials estimateBased on the totaluse of new remedial and administrative coststechnologies, the 2004 cost projections for full remediation have been reduced from $30 million to be approximately $30$6 million, of which our estimated$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 (known as “MEW”) Study Area, an eight square mile soil and groundwater contamination site located in Mountain View, California. Several PRPs for the site have estimated the total cost of remediation to be approximately $80 million. As a result of ourthe 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, and further,site. In fact, the EPA has indicated that it does not believe there is a contaminant source on the property. We aresigned a settlement agreement in settlement negotiations withMarch 2004, which transferred any future liability for investigation and remediation at the other PRPs. It is expectedsite to settle in 2004.the PRP group. The settlement isamount was not expected to be material.

	(c)		In 1997, Baker Hughes andwe entered into a settlement agreement with Prudential Insurance Company (“Prudential”) entered into a settlement agreement regarding cost recovery for the San Fernando Valley – Glendale Superfund. A Baker Hughes predecessorOne 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 cost, which issite, limited to $260,000 under our agreement with Prudential, attributed toa 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 the site. The first phase of groundwater investigation and the interim remedy have been presentedongoing assessments to the EPA.fund this remediation strategy.

(d)
	(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 believe we have contributed ade minimisamount of hazardous substancesubstances to the sitesite. In December 2004, the EPA issued us a specialde minimissettlement 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 have responded to the EPA’s inquiry. The Department of Defense, a major PRP, is attempting to settle with the City of Glen Cove separately from the rest of the PRP group. The PRP group led by the former site operator, Teledyne, is commenting on this settlement. The cleanup for the site is estimated at $40 million.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 our companieswe 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. AlthoughWe participate as a member of the technical committee to effectively manage the project, since our contribution is estimated to be 71%. The initial investigation ofat the site is incomplete, preliminarycomplete and a detailed report has been submitted to the TCEQ along with a proposed work plan. The most current cost estimatesprojections for the closure of the site are approximately $3 million. We estimate our total contribution to be in the range of 55%$5 million to 60% of that cost.$7 million; however, this projection may change once the remedial options are fully evaluated.

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(g)

In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and two of our former subsidiaries Lynes, Inc. and Baker Tubular Services, were identified as PRPs for the Malone site located on Campbell Bayou Road in Texas City, Texas. The EPA is overseeingoversees the investigation and remediation of the Malone site. The EPA has engaged in some emergency removal actions at the site. A PRP group has been formedThe investigation is underway and is evaluatingwhen complete, remedial options will be developed and submitted to the next stepsEPA for the site. Although the investigation has not been completed, theevaluation. The initial estimate for cleanup at the Malone site is $82 million.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 fromat the site in 2000. The EPA has estimated totalTotal investigation and cleanup costs are estimated by the EPA to be approximately $24 million. At this time, thereA preliminary settlement proposal has been issued for review, and our settlement cost is insufficient informationnot expected to estimate our potential contribution to the investigation and cleanup costs at this site.be material.

(i)
	(i)		In September 2003, the Company waswe were identified as ade minimisPRP by the EPA for the Operating Industries, Inc. (OII) Superfund site in Monterrey Park, California. The EPA will propose aA settlement offer to allde minimisparties was delayed, but is expected in March 2004.2005. The EPA and Steering Committee estimate cleanup costs in excess of $650 million. At this time,As of January 2005, there iswas 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 cleanupbe 4% to 7% of these costs.

     In addition to the sites mentioned above, there are four Superfund sites for which thewhere we have ongoing obligations. The remedial work at most of these sites has been completed and whichremaining operations are in thelimited to groundwater recovery andand/or monitoring. The monitoring phase. This phase of the remediation is expected tocan continue for a period of 3up to 28 years, and our30 years. Our aggregate cost for these sites is estimated to be approximatelyless 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 conditionstatements because we have established adequate reserves to cover the estimate we presently believe will be our ultimate liability with respect to the matter,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 condition or results of operations.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”“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 onfor 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; a catastrophic event causing discharges into the environment of hydrocarbons; and a material change in the allocation to us of the volume of discharge and a resulting change in our liability as a PRP with respect to a site.businesses.

ITEM 2. PROPERTIES

     We are headquartered in Houston, Texas and operate 40 principal manufacturing plants, all within the Oilfield segment, ranging in size from approximately 4,600 to 349,000333,000 square feet of manufacturing space. The total area of the plants is more than 3.23.1 million square feet, of which approximately 2.22.1 million square feet (68%) are located in the United States, 0.3 million square feet (10%(9%) are located in Canada and South America, 0.7 million square feet (22%(23%) are located in Europe, and a minimal amount of space is located in the Far East. These manufacturing plants by geographic area appear in the table below. Our principal manufacturing plants are located as follows: United

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States – Houston, Texas; Tulsa,Broken Arrow and Claremore, Oklahoma; Lafayette, Louisiana; South America – various cities in Venezuela and Buenos Aires, Argentina;Venezuela; and Europe – Aberdeen and East Kilbride, Scotland; Kirkby,Liverpool, England; Celle, Germany; Belfast, Northern Ireland.

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     We also own or lease and operate numerous service centers, shops and sales and administrative offices throughout the geographic areas in which we operate.

     We believe that our manufacturing facilities are well maintained and suitable for their intended purposes. We also have a significant investment in service vehicles, rental tools and manufacturing and other equipment.

liabilities to governmental authorities in Nigeria. The investigation in Nigeria was substantially completed during the first quarter of 2003. Based2003 and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our resultsconsolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of operations or financial condition.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 joint ventureWesternGeco formation agreement, with WesternGeco, 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 investigationU.S. agencies, the SEC or anyother authorities or the effect it may have on our consolidated financial condition.statements.

     For additional     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 see “Item 1. Business – Environmental Matters.”is contained in the “Environmental Matters” section of Item 1 herein.

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

     None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     Our Common Stock, $1.00 par value per share (the “Common Stock”), is principally traded on the New York Stock Exchange. Our Common Stock is also traded on the Pacific Exchange and the SWX Swiss Exchange. At March 3, 2004,As of February 25, 2005, there were approximately 71,00062,700 stockholders and approximately 22,62717,300 stockholders of record.

     For information regarding quarterly high and low sales prices on the New York Stock Exchange for our Common Stock during the two years ended December 31, 20032004 and information regarding dividends declared on our Common Stock during the two years ended December 31, 2003,2004 see Note 18 of the Notes to Consolidated Financial Statements in Item 8 herein.

     Information concerning securities authorized for issuance under equity compensation plans is set forth in “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters – Equity Compensation Plan Information.”16

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     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 with “Item 8. Financial Statements and Supplementary Data”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, (“BIRD”), EIMCO Process Equipment (“EIMCO”) and the Company’sour oil producing operations in West Africa as discontinued operations. The results of operations for BIRD and EIMCO are not reflected as discontinued operations for 1999 as data is not available for that year because BIRD and EIMCO were components of a larger operating unit during that year. 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, the Company and Schlumberger Limited (“Schlumberger”) createdwe formed the WesternGeco venture into which were transferredwith Schlumberger by transferring the seismic fleets, data processing assets, exclusive and nonexclusive multiclient surveys and other assets of the Company’sour Western Geophysical division and Schlumberger’s Geco–Prakla business unit. The Company and Schlumbergerdivision. We own 30% and 70% of the venture respectively. The Company accountsand Schlumberger owns 70%, and we account for this investment using the equity method of accounting.

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(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 reversalsreversal in 2003 and 2001.2003. During 2000, the Companywe recorded a restructuring charge of $29.5 million related to the Company’sour 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 the Company’sour undeveloped exploration properties in certain foreign jurisdictions. In 2000, the Companywe 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.
		During 1999, the Company developed a plan to downsize its seismic operations as a result of low activity levels combined with significant excess operational capacity experienced Included in the seismic industry.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, the Company recorded a restructuring charge of $122.8we reversed $4.2 million primarily related to its seismic operations, of which $72.1 million was recorded in cost of revenues. The major actions included in this restructuring were a reduction in workforce, terminating leases on certain vessels, the impairment of property and sale or abandonment of certain vessels. The Company also recorded a reversal in 1999 of $11.4 million of restructuring charges recorded in prior years, of which $5.0 million was recorded in selling, general and administrative expense.obligation.
(4)		(Gain) loss on disposal of assets.During 2000, the Companywe recorded a loss of $75.5 million on the sale of itsour interests in certain oil and natural gas properties and recorded gains of $7.6 million on the sale of various product lines. In 1999, the Company recorded gains on disposal of assets of $54.8 million related to the sale of two large excess real estate properties and the sale of certain assets related to its previous divestiture of a joint venture.
(5)		Cumulative effect of accounting change.See Note 1In 2003, we adopted Statement of the Notes to Consolidated Financial Statements in Item 8 hereinAccounting Standards (“SFAS”) No. 143,Accounting for descriptions of the cumulative effect of accounting changes in 2003Asset Retirement Obligations. In 2002, we adopted SFAS No. 142,Goodwill and 2001. See Note 10 of the Notes to Consolidated Financial Statements in Item 8 hereinOther Intangible Assets. In 2001, we adopted SFAS No. 133,Accounting for a description of the cumulative effect of accounting change in 2002.Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and 138.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the consolidated financial statements of the Company for the years ended December 31, 2003, 2002 and 2001 and the related Notes to Consolidated“Item 8. Financial Statements and Supplementary Data” contained in Item 8 herein.

EXECUTIVE SUMMARY

     We are engaged in the oilfield services industry and operate through six divisions – Baker Atlas, Baker Oil Tools, Baker Petrolite, Centrilift, Hughes Christensen and INTEQ – that we aggregate and refer to as the Oilfield segment. We manufacture and sell products and provide services used in the oil and natural gas industry, includinga leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and natural gas industry. We compete as one of the three largest diversified oilfield services companies. Our Oilfield segment is comprised of seven product line focused divisions. Baker Hughes Drilling Fluids (drilling fluids), Hughes Christensen (oilfield drill bits) and INTEQ (drilling and measurement–while–drilling) provide products and services used to drill oil and natural gas wells. Baker Atlas (wireline formation evaluation) and INTEQ (formation evaluation while drilling) provide formation evaluation services. Baker Atlas (tubing conveyed perforating) and Baker Oil Tools (completion equipment) provide completion systems. Baker Petrolite (oilfield specialty chemicals), Centrilift (electric submersible pumps and progressing cavity pumps) and Baker Oil Tools (workover and completion equipment) provide equipment and services used during the production phase of oil and natural gas wells. We

     Our headquarters are in Houston, Texas, and we have significant manufacturing operations in various countries including, but not limited to, the United States (Texas, Oklahoma, and Louisiana), Scotland (Aberdeen), Germany (Celle), Northern Ireland (Belfast) and Venezuela (Maracaibo). We operate in over 8090 countries around the world with headquartersand employ approximately 26,900 employees – about one–half of which work outside the U.S. Our revenue in Houston, Texas. Previously we operated a Process segment,2004 was in excess of $6 billion – approximately 35% of which manufactured and sold process equipment for separating solidscame from liquids and liquids from liquids. During 2003, we signed a definitive agreement for the sale of BIRD Machine (“BIRD”), the remaining division in this segment. We have reclassified the operating results for BIRD as discontinued operations and no longer operate in this segment.

     Ourproviding products and services are sold in highly competitive markets, and our revenues and earnings can be affected by changes in competitive prices, fluctuations in the level of activity in major markets, general economic conditions, foreign exchange fluctuations and governmental regulation. We compete with theto oil and natural gas industry’s largest diversified oilfieldcompanies operating in the U.S.

     The customers for our products and services providers, as well as many small companies. We believe that the principal competitive factors in our industry are product and service quality; availability and reliability; health, safety and environmental standards; technical proficiency and price. We consider our key business drivers to include the rig count,super–major and major integrated oil and natural gas companies, independent oil and natural gas companies and state–owned national oil companies (“NOCs”). Our ability to compete in the oilfield services market is dependent on our ability to differentiate our product and service offerings by technology, service and the price paid for the value we deliver. Our primary competitors include the other two large diversified oilfield service companies – Schlumberger and Halliburton, as well as a number of smaller competitors, including Smith, Weatherford and Grant Prideco.

     The primary driver of our business is our customers’ capital and operating expenditures dedicated to exploring, drilling, developing, and producing oil and natural gas. Our business is cyclical and is dependent upon our customers’ forecasts of future oil and natural gas prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas production. In 2004, our customers’ spending directed to both worldwide oil and North American oil and natural gas projects increased. These increases were driven by the perceived, multi–year requirement to produce more hydrocarbons to meet the growth in demand, offset production declines, increase inventory levels and currentrebuild excess productive capacity. The increases were supported by historically high oil and natural gas prices. Our customers’ spending on oil projects is expected to continue to grow in 2005 and in the near future, energy prices.with a bias towards those projects in the Middle East, Russia and the Caspian region and Africa. Spending in North America is dominated by spending on natural gas projects. In North America, customer activity is expected to grow modestly in 2005 compared with 2004 levels, which were the highest in over two decades.

     In 2003,2004, we reported revenues of $5,292.8$6,103.8 million, an 8.0%a 16.2% increase compared with 2002.2003. Income from continuing operations for 20032004 was $180.1$528.2 million compared with $229.6$177.9 million in 2002.2003. Included in income from continuing operations for 2003 are charges,

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net of tax, of $105.9 million related to our share of thea WesternGeco restructuring charge and $45.3 million related to the impairment of our investment in WesternGeco. IncludedBoth our revenues and operating profits set all time records in income from continuing operations2004.

     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 2002 is a charge, net of tax, of $86.8 million related to our share of the WesternGeco restructuring charge.

     The increase in revenue was achieved despite cautious investment by our customers, shifting markets and strong competition. Even though oilhydrocarbons. Oil and natural gas prices were at historic highs in 2004, reflecting strong demand and relatively highlow 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, oil and natural gas companies invested cautiously because ofoutpacing the conflict10.1% increase in the Middle East and ongoing concerns about the economy. On a worldwide basis, the average rig count for 2003 increased 16.9%2004 compared with 2003. In North America, our 2004 revenues increased 14.4% compared with 2003, while the average rig count increased 10.9% for 2002. Most of this increase came from land rigs2004 compared with 2003, driven primarily by land–based drilling for natural gasgas. 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 North America. Drilling activity in the Gulf of MexicoRussia and the North Sea, historically among our strongest markets, declined duringCaspian region, Latin America, the Middle East, Africa and Asia. Our European revenues in 2004 were up modestly compared with 2003, as deepwater operators re–evaluated projects and the large diversified oil and natural gas companiesdespite 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 Gulfmaintenance of Mexicoa high performance culture founded on our Core Values and Keys to Success; our product line focused organization and our focus on newbest–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 in other resource areas.

starts with our product line focused organization structure. We believe that through our critical success factors include having sufficientproduct 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 liquidityflexibility and resourcesfinancial discipline is the backbone of our effort to funddeliver differential growth at superior margins while earning an acceptable return on our investments throughout the various requirementsbusiness 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 business; managingbest price we can for our overall global manufacturing capacityproducts and services begins with our approach to ensure proper production levels; ensuring workforcecapital discipline. Over the past few years, we have invested for growth in our business, repaid debt, paid dividends and asset levels arerepurchased stock, and we expect to maintain the flexibility to be able to undertake such activities in placethe 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 line with business needs; maximizing efficienciesour business. The effort extends to every phase of our operations, including continuous improvement programs in our manufacturing facilities and service delivery processes; identifying, evaluating and implementing profit improvement strategies; introducing new technology;field operations that support our goal of flawless execution at the well site; delivering unmatched valuesite.

     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 customersability to: manage raw material and overall cost management.

     As 2004 begins, we remain focused on cost managementcomponent 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 introduction of new products. We have created a long–term strategy thatCaspian region) with customers whose spending is aimed at creating value for our stockholders throughoutexpected to increase the business cyclemost rapidly (such as NOCs), and growing our business faster while achieving superior margins compared with our major competitors. We share a common high performance culture, andin areas in which we are aligningunderrepresented (such as the Middle East); and realize price increases commensurate with the value we provide to execute our long–term strategy.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 six divisions will continue to provide Best–in–Class technology, serving our traditional marketsBusiness” and new ones, while delivering unmatched value for our customers and maximizing returns for our stockholders.“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. Whencount 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, as well as whenduring the completion of the oil and natural gas wells are completed and during actual production of the hydrocarbons. This E&P spending by oil and natural gas companies is, in turn, influenced strongly by

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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 countries,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 customerconsumer 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 and if the well hasmonth. The rig count does not reached the target depth. Rigsinclude rigs that are in transit from one location to another, are rigging up, have been drilling less than 15 days of the month, are being used in non–drilling activities, including production testing, completion and workover, or are not significant consumers of oilfield products and services are not included in the rig count.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 Canadianinland waters rig countscount increased 28.9% and 26.2%, respectively,18.5% in 20032004 compared with 20022003 due to the increase in drilling for natural gas. The U.S. – offshore rig count decreased 4.4%10.2% in 20032004 compared with 20022003 primarily related to a reduced level of spending by major diversified oil and natural gas companies who redirectedhave 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 countscount increased 5.2%8.6% in 20032004 compared with 2002.2003. The rig count in Latin America increased 14.0% as18.9% in 2004 compared with 2003, driven primarily by spending by the Mexican national oil company, PEMEX, drove rig count increases in Mexico, offsetting strike–related decreases attributed to the Venezuelan national oil company, PDVSA.Venezuela and Argentina. The North Sea rig count decreased 15.2% in 2003 decreased 11.5%2004 compared with 2002 following a 7.1% decrease in 2002 compared with 20012003 primarily driven by a declinecontinued declines in drilling activity in both the U.K. sector. Majorand 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, redirectedwhich continue to redirect spending towards other larger international projects, especially in Russia and the Caspian.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 5.0%9.0% increase in the 2003 rig count following a 12.3% increase in 20022004 compared with 2001. Rig counts in Africa declined 6.9% in 2003 compared with 2002 primarily as a result of political disruptions in Nigeria and project delays in other parts of West Africa. Rig activity2003. The rig count in the Asia Pacific region was up 3.5%11.3% in 20032004 compared with 20022003 primarily due to activity increases in India.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

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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 $31.06/a historic high of $41.51/Bbl in 2003,2004. Prices increased from the highest annual averagelow $30s/Bbl in more than a decade. Oil prices roseJanuary 2004 to a high of $37.83/$56.17/Bbl in early March due tolate October 2004, before moderating and ending the year in the low inventories, seasonally colder than normal weather,$40s/Bbl. Inventories of crude and petroleum products were relatively low throughout the disruption of Venezuelan productionyear, supporting high prices. Worldwide demand for hydrocarbons was driven by a general strikestrong worldwide economic growth, which was particularly strong in China and concerns aboutdeveloping 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, disruptionswhich 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 military operationscolder than normal winter weather. Prices fell to just above $5/mmBtu in late February, as winter weather moderated and storage remained just above the Middle East. Oilfive–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 $25.24/Bbl$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 AprilOctober. Prices fell below $5/mmBtu in November, as significant supply disruptions did not occurthe beginning of the winter was milder than normal and storage was above the market reactedfive–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 possibilityWorldwide 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 rapidsignificant than expected recoveryslowing of worldwide economic growth, particularly economic growth in IraqiChina; greater than planned growth in Russian oil production. Oil prices then increased to and remained between $30/Bbl and $32/Bbl through the balance of the year, excluding September. In September, concern rose again about a quicker than anticipated recovery in Iraqi production in the fourth quarter of 2003 and early 2004 and oil prices dropped below $27/Bbl. Theexports; Organization of Petroleum Exporting Countries (“OPEC”) reacted withexports 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 surprise 0.9 million barrels per day quota cutsignificant slowing of exports from Russia; or other factors which result in late September which sustainedoil 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 $30/BblMexico. The potential for these and other events to $32/Bbl throughcause volatility will be mitigated by the enddegree 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 2003. In early 2004, oil prices are averaging between $32/Bbl and $38/Bbl due tothis range if weather is colder than normal, weather, low inventoriesthe U.S. economy, particularly the industrial sector, exhibits greater than expected growth and improving Chinese andcontinued 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 growth expectations. In February 2004, OPEC again surprisedrecovery is weaker than expected or weather is milder than expected. During the market with a 1.0 million barrels per day quota cut and pledged to further reduce the current level of production in excess of agreed quotas by another 1.5 million barrels per day.

     During 2003, natural gas prices averaged $5.49/mmBtu, the highest level in two decades. In early 2003, natural gas traded between $5.00/mmBtu and $6.50/mmBtu, except for a two week period in late February 2003 when prices spiked to $19.38/mmBtu. Natural gas storage levels at the beginning of the injection season, which runs from April to November, were at record low levels but high summer, natural gas prices resulted in reduced industrialare expected to trade at a level necessary to curtail price sensitive demand and allowedallow storage levels to increase. Naturalrefill.

Customer Spending– Based upon our discussions with major customers, review of published industry reports and our outlook for oil and natural gas prices remaineddescribed above, $5/mmBtu until early July 2003, when it became apparent that storage injections during the summer of 2003 could approach record levelsanticipated 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 that storage would likely be fullnatural gas prices and customer spending described above, our outlook for drilling activity, as measured by the beginningBaker 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 winter withdrawal season. Prices weakened through the remainder of the injection season to a low of $3.99/mmBtu in late October.Worldwide Oil and Natural gas prices increased over the remainder of 2003 and are trading between $5/mmBtu and $7/mmBtu in early 2004.

Key Risk FactorsGas 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 that could impact our outlook 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.
•	Production controlSupply disruptions –the degreeloss of production, the inability to which individual OPEC nations and other largeexport and/or delay of activity from key oil and natural gas producingexporting countries, including but not limited to, Mexico,Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria, Norway, Russia and Russia, are willing and ableVenezuela, due to controlpolitical instability, civil unrest, labor issues or military activity. In addition, adverse weather such as hurricanes could impact production and exports of oil, to decrease or increasefacilities, causing 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 price compared with targeted oil price and changes in each country’s market share.disruptions.
•		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 is strong. The strength of the U.S. economy and economic growth in developing Asia, particularly China, will be important in 2004. 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 –a measure 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 American Petroleum Institute and worldwide estimates reported by the International Energy Agency.
•		Ability to produce natural gas– the amount of natural gas that can be produced is a function of the number 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.

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•		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.
•		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.
•		Pace of new investment –the amount oil and natural gas companies choose to invest in emerging markets and any impact it has on their spending in areas where they already have an established presence.
•		Access to capital– the ability of oil and natural gas companies to access the funds necessary to carry out their exploration and production (“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.
•		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. This resultsThese 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.
•		Supply disruptions –the loss of production and/or delay of activity from key oil exporting countries, including but not limited to, Iraq, Saudi Arabia and other Middle Eastern countries, Nigeria 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.
•		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.

Industry Outlook24

     Caution is advised that the factors described in “Forward Looking Statements” and “Business Environment” could negatively impact our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

Oil– Inventories of crude oil and products were at record low levels as 2004 began, supporting oil prices of $32/Bbl to $38/Bbl. Oil prices are expected to decline throughout 2004 and average between $26/Bbl and $34/Bbl. Factors which could support prices at the upper end of this range include stronger than expected worldwide economic growth, especially in China and the U.S., the potential for supply disruptions in the Middle East, Africa or Venezuela, the slower growth of Russian exports due to export capacity bottlenecks and OPEC’s desire and ability to maintain a higher price target to stabilize their purchasing power. Factors which could

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	•		North America – Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 7% to 9% in 2004 compared with 2003.
	•		Outside North America – Customer spending, primarily directed at developing oil supplies, is expected to increase 4% to 6% in 2004 compared with 2003.
	•		Total spending is expected to increase 5% to 7% in 2004 compared with 2003.

Drilling Activity– Based upon our outlook for oil     For additional risk factors and natural gas pricescautions regarding forward–looking statements, see the “Risk Factors Related to Our Business” and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count,“Forward–Looking Statements” sections contained herein. This list of risk factors is as follows:not intended to be all inclusive.

	•		The North American rig count is expected to increase approximately 6% to 9% in 2004 compared with 2003.
	•		Drilling activity outside of North America is expected to increase approximately 4% to 6% compared with 2003.

BUSINESS OUTLOOK

COMPANY OUTLOOK

     We expect that 2004 will be a stronger year than 2003, with revenues increasing 5% to 7%.     In our outlook for 2004,2005, we took into account the factors described herein. In 2003, 2002 and 2001,We expect that 2005 will be a stronger year than 2004, with revenues outside North America were 57.6%increasing 9% to 11%, 59.9% and 55.1% of total revenues, respectively. In 2004, wein line with the expected increase in customer spending. We expect revenues outside North America to continue this trend and to be between 55% and 60% of total revenues.

     Growththat the growth in our revenues should mirror the growth in customer spending.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 $26/$35/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding $4/an average of $5/mmBtu.

     In North America, we expect revenues to increase 7%11% to 9%13% in 20042005 compared with 2003,2004, with the majority of the increase occurring in the second half of 2004.2005. We expect spending on land land–based projects to continue to increase in 20042005 driven by demand for natural gas, following the trend evident in 2003.2004. We also expect offshore spending in the Gulf of Mexico to be flatincrease modestly in 20042005 compared with 2003.2004. 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 2004.2005.

     OutsideIn 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 5%7% to 7%9% in 20042005 compared with 2003,2004, continuing the multi–year trend of modest growth in customer spending. Spending on large projects from national oil companiesby 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 2004.2005. The Middle East, Africa and Latin America Caspian regions and Russia are expected to demonstrate above average spending increases, resultinggrow modestly in increased revenue, while growth in revenues from the North Sea may be below average.2005 compared with 2004. Our expectations for spending and revenue growth could decrease if average prices fall below $26/$35/Bbl for oil or $4/$5/mmBtu for natural gas or if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In prior years,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 profitability has been negatively affectedportion of certain restructuring and impairment charges taken by our share of WesternGeco’s operating results, which have been adversely affected by the continued weaknessWesternGeco in the seismic industry.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 offor WesternGeco to improve in 2004 as compared with prior years;continue throughout 2005; however, based on the historical trend of operating losses and weakness in the seismic industry in prior

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years, there is uncertainty regarding the future operating results of WesternGeco. Information regarding WesternGeco’s profitability in 20042005 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 earningsincome from continuing operations per diluted share in 2004 from continuing operations2005 will be in the range of $1.20$1.80 to $1.35. This does not anticipate material changes in$1.95, which includes the prices that we charge for our products.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 8090 countries including aboutover one–half of the 3435 countries having the worstlowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2003.2004. 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 such internal 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 joint 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 POLICIES AND ESTIMATES

     The discussion and analysispreparation of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. Our significant accounting policies are described in the Notes to Consolidated Financial Statements. In certain respects, the application of our significant accounting policies in the preparation of the 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 policy or 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 believe the following are the critical accounting policies used in the preparation of our consolidated financial statements as well as the significant estimates and judgments and uncertainties affecting the application of these policies. We have discussed the development and selection of theseour critical accounting policies and 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 be able to make the required payments at either contractual due dates or in the future. Over the last five years, reserves for doubtful accounts, as a percentage of total accounts receivable before reserves, have ranged from 5.2% to 7.1%. At December 31, 20032004 and 2002,2003, reserves for doubtful accounts totaled $62.8$50.5 million, or 5.2%3.6%, and $67.2$61.8 million, or 5.7%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

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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 one percentage pointfive percent change in this reserve would have had a pre–tax impact of approximately $12.1$2.5 million in 2003.2004.

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. Over the last five years, inventory reserves, as a percentage of total inventories before reserves, have ranged from 18.2% to 19.6%. At December 31, 20032004 and 2002,2003, inventory reserves totaled $221.1 million, or 17.6%, and $232.5 million, or 18.5%, and $235.9 million, or 19.1%18.7%, of gross inventory, respectively. We believe that our reserves are adequate to cover anticipated losses under current conditions; however, significantconditions. 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 one percentage point changefive percent difference in this reserve would have had a pre–tax impact of approximately $12.6$11.1 million in 2003.2004.

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 make judgments and estimates in conjunction with accounting for these assets, including depreciation and amortization methods and useful lives. Additionally,review the carrying values of these assets are reviewed 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 8090 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

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inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. We do not believe it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because theThe resulting change to our tax liability, if any, is dependent on numerous factors which cannot be reasonably estimated.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.

DISCONTINUED OPERATIONS 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 third quarteraforementioned 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 Boardplan investments were 8.50% in 2004 and 2003 and 9.00% in 2002. A 50 basis point decrease in the expected rate of Directors approved and management initiated a plan to sell BIRD, the last remaining divisionreturn on assets of our former Process segment.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. The sale closed inIn January 2004, we completed the sale of BIRD and werecorded an additional loss on the sale of $0.5 million with no tax benefit. We received $5.6 million in proceeds, which iswere subject to adjustment pending final completion ofpost–closing adjustments to the purchase price. Weprice, 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, recorded in the first quarter of 2003.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 ourthe 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 ofto 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 and $2.0 million was received by us.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 are based on available information and represent our analysis of significant changes or events that impact the comparability of reported amounts. Where appropriate, we have identified specific events and changes that affect comparability or trends and, where possible and practical, have quantified the impact of such items.

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     The table below details certain consolidated statement of operations data and their percentage of revenues for 2004, 2003 and 2002, and 2001, respectively.

Revenues

     Revenues for 2003 were $5,292.8 million, an increase of 8.0%2004 increased 16.2% compared with 20022003, reflecting a 16.9%10.1% increase in the worldwide rig counts. Rig counts act as a leading indicator for our revenues because when rigs are active, many of our products and services are required. Our products and services are used during drilling operations and then subsequently during completion of the wells and also during production of the hydrocarbons.count. Revenues in North America, which accounted for 42.4%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 24.8%28.4% increase in the

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North American rig count. Revenues outside North America, which accounted for 57.6%57.7% of total revenues, increased 3.9%4.1% compared with 2002. This increase reflects the improvement in international drilling activity, as evidenced by the 5.2% increase in the rig countscount 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 2002 were $4,901.7 million, a decrease of 2.7%2004 increased 14.3% compared with 2001. Revenues2003. Cost of revenues as a percentage of revenues was 71.6% and 72.7% for 2004 and 2003, respectively. The decrease in North America, which accounted for 40.1%cost of total revenues decreased 12.9% compared with 2001. This decrease reflectsas a percentage of revenues is primarily related to limited pricing improvement in certain markets and product lines and improved cost control measures, including lower activityrepair and maintenance costs at our INTEQ division, partially offset by increased material costs and higher employee bonus expense. A change in the U.S. landgeographic and offshore operationsproduct mix from the sale of our products and Canada, as evidenced by a 27.0% decrease in the North American rig count. Inclement weather in the Gulf of Mexico, including Tropical Storm Isidore and Hurricane Lili,services also contributed to the decline. Revenuesdecrease in the cost of revenues as a percentage of revenues. During 2004, our revenue increases came predominantly from outside North America which accounted for 59.9% of totaland our margins on revenues increased 5.6% compared with 2001. This increase reflects the improvementgenerated outside North America are typically higher than margins generated in drilling activity, particularly in the Middle East and Asia Pacific, partially offset by weaker revenues in Latin America due to the political and economic environments in Argentina and Venezuela and the impact of a labor strike in Norway.

Cost of RevenuesNorth America.

     Cost of revenues for 2003 was $3,854.9 million, an increase of 9.4%increased 9.5% compared with 2002. Cost of revenues as a percentage of revenues was 72.8%72.7% and 71.9%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 repairsrepair and maintenance (“R&M”) costs for newly developed downhole rental tools and other nonrecurring costs. We anticipate margins at INTEQ will improve in 2004 as a result of a stabilized pricing environment and improved cost control measures. In addition, corrective action was taken related to the increased R&M costs, which we anticipate will result in lower R&M costs in 2004. 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.

     Cost of revenues for 2002 was $3,525.2 million, a decrease of 1.1% compared with 2001. Cost of revenues as a percentage of revenues was 71.9% and 70.8% for 2002 and 2001, respectively. The increase in cost of revenues as a percentage of revenues was the result of our strategy not to significantly reduce our work force to match the reduced activity levels and a change in the geographic and product mix from the sale of our products and services.

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 were $830.1 million, an increase of $18.6 million, or 2.3%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, that are not expected to recur in the future, offset by improvement in the impact of foreign currency exchange activity of $18.7$18.3 million. In 2004, we anticipate corporate costs will continue to trend upward primarily due to compliance related expenditures.

     SG&A expenses for 2002 were $811.5 million, an increase of $56.4 million, or 7.5%, compared with 2001. This increase was primarily due to the impact of the weakening U.S. dollar resulting in increased foreign exchange losses of $14.8 million, increased depreciation of the cost associated with the now substantially completed implementation of SAP R/3, an enterprise–wide accounting and business application software system, of $15.2 million, and our strategy not to significantly reduce our work force to match current market activity levels.30

Reversal of Restructuring Charge

     In October 2000, our Board of Directors approved a plan to substantially exit the oil and natural gas exploration business and we recorded a restructuring chargescharge of $29.5 million, consisting of $5.5 million of severance, $7.8 million for costs to settle contractual obligations and a $16.2 million loss for the write–off of our undeveloped exploration properties in certain foreign jurisdictions. The severance charges were for approximately 50 employees, all of which have been terminated as of December 31, 2003. All of the accrued severance has been paid as of December 31, 2003.

million. Included in the costs to settle contractual obligationsrestructuring 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. Also 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

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abandon further involvement in this project. Subsequently, in 2001, a third party agreed to assume the remaining obligations in exchange for our interest in the project. Accordingly, we reversed $4.2 million related to this obligation. All contractual obligations associated with this plan have been paid as of December 31, 2003.

Impairment of Investment in Affiliate

     AsIn 2003, as a result of the continuingcontinued weakness in the seismic industry, we evaluated the carrying value of our investment in WesternGeco and recorded an impairment loss of $45.3 million in 2003 to write–down the investment to its fair value. The fair value was determined using a combination of a market valuecapitalization and discounted cash flows approach. We were assisted in the determination of the fair value by an independenta third party. Although not anticipated, further declines in the fair value of the investment in WesternGeco would result in additional impairments. We cannot predict if additional impairments of our investment in WesternGeco will be necessary in the future because the environment in the seismic industry continues to be uncertain.

Equity in Income (Loss) of Affiliates

     Equity in income (loss) of affiliates relateswas $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 shareportion of the income (loss)restructuring and impairment charge taken by WesternGeco in the third quarter of affiliates accounted for using the equity method of accounting. Our most significant equity method investment is our 30% interest in WesternGeco.2003. During 2003, the operating results of WesternGeco continued to be adversely affected by the continuing weakness in the seismic industry. Asindustry 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. Our portion of these charges was $135.7 million and is recorded in equity in income (loss) of affiliates.

     Equity in income (loss) of affiliates decreased $115.5 million for 2002 compared with 2001. The decrease is primarily related to a $300.7 million restructuring charge recorded by WesternGeco for impairment of its multiclient library, reductions in workforce, closing land–based seismic operations in the U.S. lower 48 states and Canada and reducing its marine seismic fleet. Our portion of this charge was $90.2 million and was recorded in equity in income (loss) of affiliates.

     Operating results for WesternGeco are expected to continue to improve in 2004;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.

     IncludedInterest 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 equityApril 2004. The lower total debt levels are the result of the repayment of $350.0 million of long–term debt in income (loss)the second quarter of affiliates for 2001 was $7.92004, which decreased interest expense by $16.0 million related toin 2004 compared with 2003. Additionally, the amortization of goodwill associatedinterest rate swap agreement decreased interest expense by $4.1 million in 2004 compared with equity method investments. In conjunction with the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 142,Goodwill and Other Intangible Assets, we discontinued the amortization of goodwill associated with equity method investments effective January 1, 2002.

Interest Expense2003.

     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. TotalThe lower total debt levels decreased $63.4 million primarily due toare 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.

     Interest expense for 2002 decreased $15.2 million compared with 2001 due to lower total debt levels resulting from cash flows from operations coupled with lower weighted average interest rates on our short–term debt, commercial paper and interest rate swaps. The approximate weighted average interest rate on short–term debt and commercial paper was 1.8% for 2002 compared with 4.0% for 2001.

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

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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, and 2001, the amount of additional taxes resulting from operations of the venture was $40.2 million and $14.8 million, respectively.million.

     During 2003, a current year 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. In 2001, a benefit of $23.5 million was recognized as a result of the settlement of the IRS examination of certain 1994 through 1997 pre–acquisition tax returns and related refund claims of Western Atlas Inc.

     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 /orand/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 addresses financial accounting and reporting for obligations associated with the retirement of long–lived assets. 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 an independenta 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 appropriately financing our business is to maintain adequate financial resources and access to additional liquidity. During the last three years,2004, cash flows from operations have been ourand short–term borrowings were the principal sourcesources of funding. We anticipate that this trendcash flows from operations will continuecover our liquidity needs in 2004.2005. We also have a $500.0 million three–year committed revolving credit facility that would provide an ample source ofprovides back–up liquidity that would be available in the event of an unanticipated significant demand on cash flowflows 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 the Company.our company. In 2003,2004, we used cash for a mixvariety of activities including working capital needs, payment of dividends, repaymentrepayments of debt, repurchase of common stockindebtedness and capital expenditures. In 2004, we expect that this trend will continue, as we do not anticipate any additional material demands, commitments or other events that would require significant outlays of cash.

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Cash Flows

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

     Cash flow statementsStatements of cash flows for companiesentities 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 and, as such,changes. As a result, changes reflected in certain accounts on the consolidated statements of cash flow statementsflows may not reflect the changes in corresponding accounts on the consolidated balance sheets. During 2003, 2002 and 2001, these changes in foreign currency exchange rates were significant and resulted in corresponding changes in the foreign currency translation adjustment account.

     During 2003, we revised our capital expenditure reporting procedures for certain rental tools and engineering prototype tools. Previously, amounts for these items were reported as transfers from inventory to property, plant and equipment; however, they will now be reported as capital expenditures. In addition, depreciation related to certain of these tools that had not previously been included in total depreciation and amortization expense is now included in this caption. The consolidated statements of cash flows for the years ended December 31, 2002 and 2001 have been reclassified to give effect to this change. There was no impact to the consolidated statements of operations or the consolidated balance sheets for any of the periods presented.

Operating Activities

     Cash flows from operating activities have been relatively consistent duringsteadily increasing over the last three years and we expect this trend to continue in 2004.2005. We attribute the stabilityincreases in our cash flowflows to successful management of working capital and consistentincreasing levels of income from continuing operations adjusted for non–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 items.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 fromof continuing operations increased $32.2$31.5 million in 2003 compared with 2002. The primary reason for this increase was improved2002 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 $15.4$13.9 million in cash.cash compared with providing $86.4 million in cash in 2002. This was primarily due to increasesthe increase in revenuerevenues offset by a reduction in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately two days.
	•		A decrease in inventory in 2003 provided $21.5$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 accrued compensation and other accruedcurrent liabilities in 2003 provided $31.8$16.5 million in cash.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. TheseTheses changes were partially offset by $59.8 million morean increase in income tax payments of $59.8 million in 2003 compared with 2002.

     Our pension contributions in 2003 were approximately $28.0 million, an increase of approximately $19.0 million compared with the prior year, due to the formation of a new U.S. pension plan in 2002. In 2004, we expect pension contributions to increase and to be between $35.0 million and $40.0 million.

     Cash flows from operating activities from continuing operations decreased $24.3 million in 2002 compared with 2001 primarily due to decreased operating performance attributable to our decreased revenues. In addition, working capital increased with the effect of decreasing cash flows from operating activities.

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

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