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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10–K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

OR

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

Commission File Number 1–9397

Baker Hughes Incorporated

Registrant’s telephone number, including area code: (713) 439–8600

Securities Registered Pursuant to Section 12(b) of the Act:

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [  ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form 10–K. [X]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in the Exchange Act Rule 12b–2). YES [X] NO [  ]

     The aggregate market value of the voting and non–voting Common Stock held by non–affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing price on June 27, 2003 reported by the New York Stock Exchange) was approximately $10,762,427,000.

     At March 3, 2004, the registrant has outstanding 332,602,611 shares of Common Stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of Registrant’s 2003 Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2004 are incorporated by reference into Part III of this Form 10–K.

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Baker Hughes Incorporated

INDEX

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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 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 at www.bakerhughes.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”).

     We have adopted a Business Code of Conduct to provide guidance to our directors, officers and employees on matters of business conduct and ethics, including compliance standards and procedures. We have also required our principal executive officer, principal financial officer and principal accounting officer to sign a Code of Ethical Conduct Certification. Our Business Code of Conduct and Code of Ethical Conduct Certification are available on the Investor Relations section of our website at 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, Governance Committee, Finance Committee, Executive Committee and Compensation Committee 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 six operating divisions – Baker Atlas, Baker Oil Tools, Baker Petrolite, Centrilift, Hughes Christensen and INTEQ – that have been aggregated to comprise 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, completion, production of oil and natural gas wells and in reservoir measurement and evaluation. The principal markets include all major oil and natural gas producing regions of the world, including 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 and Schlumberger Limited (“Schlumberger”), as well as other similar businesses.

     For additional industry segment information for the three years ended December 31, 2003, 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 perforating 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 drilled. Wireline logging measurements can be made before the well’s protective steel casing is set (open hole logging), after casing has been set (cased hole logging) or during production (production logging).

     Perforating Services. 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 perforating 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.

     Baker Atlas’ primary formation evaluation and perforating competitors are Schlumberger, Halliburton Company (“Halliburton”) and Precision Drilling Corporation.

     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 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 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 production from more than one zone in a conventional vertical well, from multiple lateral zones, or even from multiple reservoirs in a field. 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,” versus conventional tools, which can only be set inside casing. Thru–tubing inflatables enable remedial operations in live 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.

     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, its primary competitors are Halliburton, Schlumberger and Weatherford. Its major competitors in fishing are Smith International, Inc. (“Smith”) and Weatherford.

     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’s products provide measurable productivity increases, 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 system maintenance. Especially susceptible to hydrates are subsea wells and flowlines, particularly in deepwater environments.
	•		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 iron in tubulars, valves and other system equipment. The H2S eats away at the iron source, potentially causing failures and leaks. Additionally, the reaction creates iron sulfide which can impair treating systems and cause blockages. Baker Petrolite offers a variety of corrosion inhibitors and H2S scavengers.
	•		Emulsion breakers – While water and oil typically do not mix, 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. 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 competitors are GE Water Technologies, Nalco Company and Champion Servo.

     Key business drivers for Baker Petrolite include oil and natural gas production levels as well as 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.

     Opportunities for competitive differentiation for both ESP and PCP systems include:

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

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

     Key business drivers for Centrilift include oil production levels as well as the current and expected future oil prices.

Hughes Christensen

     Hughes Christensen is a leading manufacturer and supplier of drill bit products, primarily Tricone® roller cone bits and fixed polycrystalline diamond compact (“PDC”) cutter bits, to the worldwide oil and natural gas, mining and geothermal industries. The primary objective of drill bits is to create 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® 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 longer life than Tri–cone® bits. A rental market is developing 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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     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.

     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 direction that it is oriented due to its angled housing, gradually guiding the wellbore through an arc.

     INTEQ was a pioneer and is a leader in the development and use of 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.

     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 rocks 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 allow “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, 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.

     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.

     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 acquisition and processing 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 characteristics of the geologic formations through which the sound waves moved 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 conducts 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–dimensional surveys for delineating exploration targets. WesternGeco also conducts time–lapse, four–dimensional seismic surveys for monitoring reservoir fluid movement over time. Seismic information can reduce field development and production costs by reducing turnaround time, lowering drilling risks and minimizing the number of wells necessary to explore and develop reservoirs. WesternGeco’s major competitors in providing these services are Compagnie Generale de Geophysique, Veritas DGC, Inc. and Petroleum Geo–Services ASA.

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 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 exchange fluctuations and governmental regulation. We compete with the oil and natural gas industry’s largest diversified oilfield services providers, as well as many small companies. We believe that the principal competitive factors in our industries are product and service quality; availability and reliability; health, safety and environmental standards; technical proficiency and price.

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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 80 countries worldwide, and our operations are subject to the risks inherent in doing business in multiple countries with various laws and differing political environments. These risks include, but are not limited to, war, boycotts, political and economic changes, corruption, terrorism, expropriation, foreign currency controls, taxes and changes in currency exchange rates. Although it is impossible to predict the likelihood of such occurrences or their effect on the Company, division and corporate management 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, 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.

RAW MATERIALS

     We purchase various raw materials 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 based chemical feed stocks. All of these materials are available from numerous sources. We have not experienced any significant shortages of raw 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 interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long–term.

OTHER DEVELOPMENTS

     In 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 into a definitive agreement for the sale of BIRD. Accordingly, we classified BIRD as a discontinued operation 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 in January 2004, and we received proceeds of $5.6 million, which is subject to adjustment pending final completion of the purchase price. We retained certain accounts receivable, inventories and other assets.

     In February 2004, we completed the sale of our minority interest in Petreco International and received proceeds of $35.8 million, of which $7.4 million is held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We do not believe the transaction is material to our financial condition or results of operations.

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EMPLOYEES

     At December 31, 2003, we had approximately 26,650 employees, as compared with approximately 26,500 employees at December 31, 2002. Approximately 2,400 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, 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

     Our past and present operations include activities which are subject to domestic (including U. S. federal, state and local) and international regulations with regard to air and water quality and other environmental matters. We believe we are in substantial compliance with these regulations. Regulation in this area continues to evolve and changes in standards of enforcement of existing regulations, as well as the enactment and enforcement of new legislation, may require us and our customers to modify, supplement or replace equipment or facilities or to change or discontinue present methods of operation. We are 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 use in operations. Remediation costs are accrued based on estimates of known environmental remediation 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 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, 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.

     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 contributed to the site by us to the total volume of waste 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 sites discussed below. The United States Environmental Protection Agency (the “EPA”) and appropriate state agencies are supervising investigative and cleanup activities at these sites. For 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. When used in the descriptions of the sites below, the word de minimis means less than a 1% contribution rate.

	(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 estimate the total remedial and administrative costs to be approximately $30 million, of which our estimated contribution is approximately 1.8%.
	(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 our 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, the EPA has indicated that it does not believe there is a contaminant source on the property. We are in settlement negotiations with the other PRPs. It is expected to settle in 2004. The settlement is not expected to be material.
	(c)		In 1997, Baker Hughes and Prudential Insurance Company (“Prudential”) entered into a settlement agreement regarding cost recovery for the San Fernando Valley – Glendale Superfund. A Baker Hughes predecessor 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 the cost, which is limited to $260,000 under our agreement with Prudential, attributed to the cleanup of the site. The first phase of groundwater investigation and the interim remedy have been presented to the EPA.
	(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 a de minimis amount of hazardous substance to the site 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.
	(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 companies contributed to the site is estimated to be less than 0.5%.
	(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. Although the investigation of the site is incomplete, preliminary cost estimates for the closure of the site are approximately $3 million. We estimate our total contribution to be in the range of 55% to 60% of that cost.

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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 overseeing 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 formed and is evaluating the next steps for the site. Although the investigation has not been completed, the initial estimate for cleanup at the Malone site is $82 million. 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 from the site in 2000. The EPA has estimated total investigation and cleanup costs to be $24 million. At this time, there is insufficient information to estimate our potential contribution to the investigation and cleanup costs at this site.
	(i)		In September 2003, the Company was identified as a de minimis PRP by the EPA for the Operating Industries, Inc. (OII) Superfund site in Monterrey Park, California. The EPA will propose a settlement to all de minimis parties in March 2004. The EPA and Steering Committee estimate cleanup costs in excess of $650 million. At this time, there is insufficient information to estimate our potential contribution to cleanup costs.
	(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 to cleanup costs.

     In addition to the sites mentioned above, there are four sites for which the remedial work has been completed and which are in the groundwater recovery and monitoring phase. This phase of the remediation is expected to continue for a period of 3 to 28 years, and our aggregate cost for these sites is estimated to be approximately $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 financial condition because we have established adequate reserves to cover the estimate we presently believe will be our ultimate liability with respect to the matter, 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 financial condition or results of operations. See Note 16 of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of environmental matters.

     “Environmental Matters” contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “Forward–Looking Statement”). The words “will,” “believe,” “to be,” “expect,” “estimate” and similar expressions are intended to identify forward–looking statements. Our expectations regarding our compliance with Environmental Regulations and our expenditures to comply with Environmental Regulations, including (without limitation) our capital expenditures on 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; unexpected, adverse outcomes with respect to sites where we have been named as a PRP, including (without limitation) the 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; 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.

ITEM 2. PROPERTIES

     We are headquartered in Houston, Texas and operate 40 principal manufacturing plants, ranging in size from approximately 4,600 to 349,000 square feet of manufacturing space. The total area of the plants is more than 3.2 million square feet, of which approximately 2.2 million square feet (68%) are located in the United States, 0.3 million square feet (10%) are located in Canada and South America, 0.7 million square feet (22%) 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, Oklahoma; Lafayette, Louisiana; South America – various cities in Venezuela and Buenos Aires, Argentina; and Europe – Aberdeen and East Kilbride, Scotland; Kirkby, England; Celle, Germany; Belfast, Ireland. 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.

ITEM 3. LEGAL PROCEEDINGS

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

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

     By the Order, dated September 12, 2001 (previously disclosed by us and incorporated by reference in this annual report as Exhibit 99.1), we agreed to cease and desist from committing or causing any violation and any future violation of Section 13(b)(2)(A) and Section 13(b)(2)(B) of the Exchange Act. Such Sections of the Exchange Act require issuers to (x) make and keep books, records and accounts, which, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the issuer and (y) devise and maintain a system of internal accounting controls sufficient to provide reasonable assurances that: (i) transactions are executed in accordance with management’s general or specific authorization; and (ii) transactions are recorded as necessary: (I) to permit preparation of financial statements in conformity with generally accepted accounting principles or any other criteria applicable to such statements, and (II) to maintain accountability for assets.

     On March 25, 2002, a former employee alleging improper activities relating to Nigeria filed a civil complaint against the Company in the 281st District Court in Harris County, Texas, seeking back pay and damages, including future lost wages. On August 2, 2002, the same former employee filed substantially the same complaint against the Company in the federal district court for the Southern District of Texas. Through our insurer, we finalized a settlement agreement with the former employee. Final settlement documents were fully executed on December 2, 2003, and the case was formally dismissed, with prejudice, by order of the federal court on December 19, 2003. The state court case had been previously dismissed. The settlement was not material to the Company.

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     On March 29, 2002, we announced that we had been advised that the SEC and the DOJ are conducting investigations into allegations of violations of law relating to Nigeria and other related matters. The SEC has issued a formal order of investigation into possible violations of provisions under the FCPA regarding anti–bribery, books and records and internal controls, and the DOJ has asked to interview current and former employees. On August 6, 2003, the SEC issued a subpoena seeking information about our operations in Angola and Kazakhstan as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and the DOJ. In addition, we are conducting internal investigations into these matters. The SEC and the DOJ have a broad range of sanctions they may seek to impose in appropriate circumstances including, but not limited to, injunctive relief, disgorgement, fines and penalties, and modifications to business practices and compliance programs, as well as civil or criminal charges against individuals. It is not possible to accurately predict at this time when such investigations will be completed, what, if any, actions may be taken by the SEC, DOJ or other authorities and the effect thereof on the Company.

     Our ongoing internal investigation with respect to certain operations in Nigeria has identified apparent deficiencies in our books and records and internal controls, and potential liabilities to governmental authorities in Nigeria. The investigation was substantially completed during the first quarter of 2003. Based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our results of operations or financial condition.

     The Department of Commerce, Department of the Navy and 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 venture formation agreement with WesternGeco, we owe indemnity to WesternGeco for certain matters. We are cooperating fully with the U.S. agencies. Based on current information, we cannot predict the outcome of the investigation or any effect it may have on our financial condition.

     For additional information see “Item 1. Business – Environmental Matters.”

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

     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, there were approximately 71,000 stockholders and approximately 22,627 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, 2003 and information regarding dividends declared on our Common Stock during the two years ended December 31, 2003, 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.”

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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” herein.

NOTES TO SELECTED FINANCIAL DATA

(1)		Discontinued operations. The selected financial data has been reclassified to reflect BIRD Machine (“BIRD”), EIMCO Process Equipment (“EIMCO”) and the Company’s 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”) created the WesternGeco venture into which were transferred the seismic fleets, data processing assets, exclusive and nonexclusive multiclient surveys and other assets of the Company’s Western Geophysical division and Schlumberger’s Geco–Prakla business unit. The Company and Schlumberger own 30% and 70% of the venture, respectively. The Company accounts 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 reversals in 2003 and 2001. During 2000, the Company recorded a restructuring charge of $29.5 million related to the Company’s 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’s undeveloped exploration properties in certain foreign jurisdictions. In 2000, the Company also recorded a $6.0 million restructuring charge in connection with the 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 in the seismic industry. Accordingly, the Company recorded a restructuring charge of $122.8 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.
(4)		(Gain) loss on disposal of assets. During 2000, the Company recorded a loss of $75.5 million on the sale of its 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 1 of the Notes to Consolidated Financial Statements in Item 8 herein for descriptions of the cumulative effect of accounting changes in 2003 and 2001. See Note 10 of the Notes to Consolidated Financial Statements in Item 8 herein for a description of the cumulative effect of accounting change in 2002.

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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 Financial Statements 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, including drilling, formation evaluation, completion and production of oil and natural gas wells. We have operations in over 80 countries around the world, with headquarters in Houston, Texas. Previously we operated a Process segment, which manufactured and sold process equipment for separating solids 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.

     Our 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 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 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, oil and natural gas production levels and current and expected future energy prices.

     In 2003, we reported revenues of $5,292.8 million, an 8.0% increase compared with 2002. Income from continuing operations for 2003 was $180.1 million, compared with $229.6 million in 2002. Included in income from continuing operations for 2003 are charges, net of tax, of $105.9 million related to our share of the WesternGeco restructuring charge and $45.3 million related to the impairment of our investment in WesternGeco. Included in income from continuing operations 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 oil and natural gas prices were relatively high in 2003, oil and natural gas companies invested cautiously because of the conflict in the Middle East and ongoing concerns about the economy. On a worldwide basis, the average rig count for 2003 increased 16.9% compared with the average rig count for 2002. Most of this increase came from land rigs drilling for natural gas in North America. Drilling activity in the Gulf of Mexico and the North Sea, historically among our strongest markets, declined during 2003 as deepwater operators re–evaluated projects and the large diversified oil and natural gas companies in the North Sea and Gulf of Mexico focused on new opportunities in other resource areas.

     We believe that our critical success factors include having sufficient financial liquidity and resources to fund the various requirements of the business; managing our overall global manufacturing capacity to ensure proper production levels; ensuring workforce and asset levels are in place and in line with business needs; maximizing efficiencies in our manufacturing and service delivery processes; identifying, evaluating and implementing profit improvement strategies; introducing new technology; flawless execution at the well site; delivering unmatched value to our customers and overall cost management.

     As 2004 begins, we remain focused on cost management and the introduction of new products. We have created a long–term strategy that is aimed at creating value for our stockholders throughout the business cycle and growing our business faster while achieving superior margins compared with our major competitors. We share a common high performance culture, and we are aligning to execute our long–term strategy. Our six divisions will continue to provide Best–in–Class technology, serving our traditional markets and new ones, while delivering unmatched value for our customers and maximizing returns for our stockholders.

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 of oil and natural gas reserves. An indicator for this spending is the rig count. 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 when the oil and natural gas wells are completed and during actual production of the hydrocarbons. This 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, 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 customer 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 has not reached the target depth. 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. 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.

     U.S. – land and Canadian rig counts increased 28.9% and 26.2%, respectively, in 2003 compared with 2002 due to the increase in drilling for natural gas. The U.S. – offshore rig count decreased 4.4% in 2003 compared with 2002 primarily related to a reduced level of spending by major diversified oil and natural gas companies who redirected a portion of their spending towards larger international projects.

     Outside North America, rig counts increased 5.2% in 2003 compared with 2002. The rig count in Latin America increased 14.0% as 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. The North Sea rig count in 2003 decreased 11.5% compared with 2002 following a 7.1% decrease in 2002 compared with 2001 primarily driven by a decline in drilling activity in the U.K. sector. Major diversified oil and natural gas companies redirected spending towards other larger international projects, especially in Russia and the Caspian. Activity in the Middle East continued to rise steadily with a 5.0% increase in the 2003 rig count, following a 12.3% increase in 2002 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 activity in the Asia Pacific region was up 3.5% in 2003 compared with 2002 primarily due to activity increases in India.

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/Bbl in 2003, the highest annual average in more than a decade. Oil prices rose to a high of $37.83/Bbl in early March due to low inventories, seasonally colder than normal weather, the disruption of Venezuelan production by a general strike and concerns about the potential for significant supply disruptions as a result of military operations in the Middle East. Oil prices fell to a low of $25.24/Bbl in late April as significant supply disruptions did not occur and the market reacted to the possibility of a more rapid than expected recovery in Iraqi 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. The Organization of Petroleum Exporting Countries (“OPEC”) reacted with a surprise 0.9 million barrels per day quota cut in late September which sustained oil prices of $30/Bbl to $32/Bbl through the end of 2003. In early 2004, oil prices are averaging between $32/Bbl and $38/Bbl due to colder than normal weather, low inventories and improving Chinese and U.S. economic growth expectations. In February 2004, OPEC again surprised 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 industrial demand and allowed storage levels to increase. Natural gas prices remained above $5/mmBtu until early July 2003, when it became apparent that storage injections during the summer of 2003 could approach record levels and that storage would likely be full by the beginning of the winter withdrawal season. Prices weakened through the remainder of the injection season to a low of $3.99/mmBtu in late October. Natural gas prices increased over the remainder of 2003 and are trading between $5/mmBtu and $7/mmBtu in early 2004.

Key Risk Factors

     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 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.

•		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 price compared with targeted oil price and changes in each country’s market share.
•		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.
•		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 results 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.
•		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 Outlook

     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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result in oil prices at the lower end of the range include slower than expected economic growth in the U.S. and China, sooner than expected increases in Iraqi production growth and increased production from OPEC members Algeria, Libya and Nigeria, challenging the Persian Gulf members of OPEC to act as the swing producers.

     Natural Gas – In 2004, prices are expected to trade between $4/mmBtu and $7/mmBtu. Natural gas could trade at the top of this range if weather is colder than normal, the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of customer spending are not sufficient to support the growth of natural gas production. Prices could move to the bottom of this range if the U.S. economic recovery is weaker than expected or weather is milder than expected. During the summer, natural gas prices are expected to trade at a level necessary to curtail price sensitive demand and allow storage to refill.

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

	•		North America – Spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 7% to 9% in 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 and natural gas prices and customer spending described above, our outlook for drilling activity, as measured by the Baker Hughes rig count, is as follows:

	•		The North American rig count is expected to increase approximately 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.

COMPANY OUTLOOK

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

     Growth in our revenues should mirror the growth in customer spending. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China and OPEC discipline, resulting in an oil price exceeding $26/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding $4/mmBtu.

     In North America, we expect revenues to increase 7% to 9% in 2004 compared with 2003, with the majority of the increase occurring in the second half of 2004. We expect spending on land based projects to continue to increase in 2004 following the trend evident in 2003. We also expect offshore spending in the Gulf of Mexico to be flat in 2004 compared with 2003. 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.

     Outside North America, we expect revenues to increase 5% to 7% in 2004 compared with 2003, continuing the multi–year trend of modest growth in customer spending. Spending on large projects from national oil companies 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. The Middle East, Latin America, Caspian regions and Russia are expected to demonstrate above average spending increases, resulting in increased revenue, while growth in revenues from the North Sea may be below average. Our expectations for spending and revenue growth could decrease if prices fall below $26/Bbl for oil or $4/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, our profitability has been negatively affected by our share of WesternGeco’s operating results, which have been adversely affected by the continued weakness in the seismic industry. We expect the operating results of WesternGeco to improve in 2004 as compared with prior years; however, based on the 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 2004 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.

     Based on the above forecasts, we believe that earnings per share in 2004 from continuing operations will be in the range of $1.20 to $1.35. This does not anticipate material changes in the prices that we charge for our products. 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 could impact operating results positively or negatively.

     We do business in approximately 80 countries including about one–half of the 34 countries having the worst scores in Transparency International’s Corruption Perception Index (“CPI”) survey for 2003. 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 the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. We anticipate that the devotion of significant resources to compliance related issues, including the necessity for 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. In order to provide products and services in some of these countries, we may in the future utilize joint ventures, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with our Business Code of Conduct.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     The discussion and analysis 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 these 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.

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, 2003 and 2002, reserves for doubtful accounts totaled $62.8 million, or 5.2%, and $67.2 million, or 5.7%, 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 point change in this reserve would have had a pre–tax impact of approximately $12.1 million in 2003.

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, 2003 and 2002, inventory reserves totaled $232.5 million, or 18.5%, and $235.9 million, or 19.1%, of gross inventory, respectively. We believe that our reserves are adequate to cover anticipated losses under current conditions; however, 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 change in this reserve would have had a pre– tax impact of approximately $12.6 million in 2003.

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, 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 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 80 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 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 the resulting change to our tax liability, if any, is dependent on numerous factors which cannot be reasonably estimated. 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

     In the third quarter of 2003, our Board of Directors approved and management initiated a plan to sell BIRD, the last remaining division of our former Process segment. In October 2003, we signed a definitive agreement for the sale of BIRD 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 in January 2004 and we received $5.6 million in proceeds, which is subject to adjustment pending final completion of the purchase price. We retained certain accounts receivable, inventories and other assets.

     In December 2002, we entered into exclusive negotiations for the sale of our interest in 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 November 2002, we sold EIMCO Process Equipment (“EIMCO”), a division of our former Process segment, and recorded a loss on 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 of the purchase price. In 2003, all purchase price adjustments were completed, resulting in the release of the escrow balance, of which $2.9 million was returned to the buyer and $2.0 million was received by us. In 2003, we also recorded an additional loss on 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.

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

Revenues

     Revenues for 2003 were $5,292.8 million, an increase of 8.0% compared with 2002 reflecting a 16.9% increase in 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. Revenues in North America, which accounted for 42.4% 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% increase in the

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North American rig count. Revenues outside North America, which accounted for 57.6% of total revenues, increased 3.9% compared with 2002. This increase reflects the improvement in international drilling activity, as evidenced by the 5.2% increase in rig counts 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.

     Revenues for 2002 were $4,901.7 million, a decrease of 2.7% compared with 2001. Revenues in North America, which accounted for 40.1% of total revenues, decreased 12.9% compared with 2001. This decrease reflects lower activity in the U.S. land and offshore operations 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, also contributed to the decline. Revenues outside North America, which accounted for 59.9% of total revenues, increased 5.6% compared with 2001. This increase reflects the improvement 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 Revenues

     Cost of revenues for 2003 was $3,854.9 million, an increase of 9.4% compared with 2002. Cost of revenues as a percentage of revenues was 72.8% and 71.9% 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 repairs 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 2003 were $830.1 million, an increase of $18.6 million, or 2.3% 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 exchange activity of $18.7 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.

Reversals 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 restructuring charges 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.

     Included in the costs to settle contractual obligations was $1.1 million related to an oil and natural gas property in Angola. The property was sold in 2003 and we reversed the liability related to this contractual obligation. 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

     As a result of the continuing 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 value and discounted cash flows approach. We were assisted in the determination of the fair value by an independent 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 relates to our share of the income (loss) of affiliates accounted for using the equity method of accounting. Our most significant equity method investment is our 30% interest in WesternGeco. During 2003, the operating results of WesternGeco continued to be adversely affected by the continuing weakness in the seismic industry. 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 improve in 2004; 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.

     Included in equity in income (loss) of affiliates for 2001 was $7.9 million related to the amortization of goodwill associated 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 Expense

     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. Total debt levels decreased $63.4 million primarily due to 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 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.

     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 that these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. We have received tax assessments from various taxing authorities and are currently at varying stages of appeals and /or litigation regarding these matters. We have provided for the amounts we believe will ultimately result from these proceedings. We believe we have substantial defenses to the questions being raised and will pursue all legal remedies should an unfavorable outcome result. However, resolution of these matters involves uncertainties and there are no assurances that the outcomes will be favorable.

Cumulative Effect of Accounting Change

     On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 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 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 independent 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, cash flows from operations have been our principal source of funding. We anticipate that this trend will continue in 2004. We also have a $500.0 million three–year committed revolving credit facility that would provide an ample source of back–up liquidity that would be available in the event of an unanticipated significant demand on cash flow that could not be funded by operations or short–term borrowings.

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of the Company. In 2003, we used cash for a mix of activities including working capital needs, payment of dividends, repayment of debt, repurchase of common stock 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 statements for companies 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 reflected in certain accounts on the cash flow statements 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 during the last three years and we expect this trend to continue in 2004. We attribute the stability in our cash flow to successful management of working capital and consistent levels of income from continuing operations adjusted for non–cash items.

     Cash flows from operating activities from continuing operations increased $32.2 million in 2003 compared with 2002. The primary reason for this increase was improved 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 million in cash. This was due to increases in revenue 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 million in cash as we increased our focus on improving the utilization of inventory on hand.
	•		An increase in accounts payable and accrued compensation and other accrued liabilities provided $31.8 million in cash. This was due to increased activity, increased employee compensation accruals, better management of our accounts payable and increased accruals for our self insurance programs. These changes were partially offset by $59.8 million more in income tax payments 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:

•

A decrease in accounts receivable in 2002 provided $87.2 million in cash primarily due to decreases in revenues as days sales outstanding remained unchanged in 2002 compared with 2001.

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	•		A decrease in inventory in 2002 provided $17.5 million in cash as we increased our focus on improving the utilization of inventory on hand.
	•		A decrease in accounts payable and accrued compensation and other accrued liabilities in 2002 used $219.5 million in cash. This was due to decreased activity, decreased employee compensation accruals and the payment of $31.0 million more in income taxes in 2002 compared with 2001.

Investing Activities

     Our principal recurring investing activity is the funding of capital expenditures to improve the productivity of operations. Expenditures for capital assets totaled $405.2 million, $356.4 million and $326.0 million for 2003, 2002 and 2001, respectively. The increase in capital expenditures in 2003 compared with 2002 is due to expenditures necessary to support our growth and operations. The majority of these expenditures were for machinery and equipment and rental tools.

     We made two acquisitions in 2003 having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. As a result of these acquisitions, we recorded approximately $3.9 million of goodwill and $9.6 million of intangible assets through December 31, 2003. The purchase prices are allocated based on fair values of the acquisitions and may be subject to change based on the final determination of the purchase price allocation. In addition, during 2003, we invested $38.1 million in affiliates, of which $30.1 million related to the Company’s 50% interest in the QuantX Wellbore Instrumentation venture, which is engaged in the permanent in–well monitoring market.

     During 2002, we made three acquisitions having an aggregate cash purchase price of $39.7 million, net of cash acquired. As a result of these acquisitions, we recorded approximately $28.4 million of goodwill. In addition, during 2002, we invested $16.5 million in Luna Energy, L.L.C. (“Luna Energy”), a venture formed to develop, manufacture, commercialize, sell, market and distribute downhole fiber optic and other sensors for oil and natural gas exploration, production, transportation and refining applications. We have a 40% ownership interest in Luna Energy and account for this investment using the equity method of accounting.

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

     Proceeds from disposal of assets were $66.8 million, $77.7 million and $77.6 million for 2003, 2002 and 2001, respectively. These disposals relate to machinery, rental tools and equipment no longer used in operations that were sold throughout the year.

     In January 2004, we completed the sale of BIRD and received $5.6 million in proceeds, which is subject to adjustment pending final completion of the purchase price. In addition, in February 2004, we completed the sale of our minority interest in Petreco International and received proceeds of $35.8 million, of which $7.4 million is held in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. We do not believe the transaction is material to our financial condition or results of operations.

Financing Activities

     We had net borrowings of commercial paper and other short–term debt of $4.5 million during 2003 compared with net repayments of $163.7 million and $67.9 million in 2002 and 2001, respectively. We also repaid the $100.0 million 5.8% Notes due February 2003. The repayment was funded with cash on hand, cash flow from operations and the issuance of commercial paper.

     Total debt outstanding at December 31, 2003 was $1,484.4 million, a decrease of $63.4 million compared with December 31, 2002. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.31 at December 31, 2003 and 2002.

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

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     During 2002, we terminated two interest rate swap agreements that had been entered into in prior years. These agreements had been designated and had qualified as fair value hedging instruments. Upon termination, we received proceeds totaling $15.8 million. The deferred gains of $4.8 million and $11.0 million are being amortized as a reduction of interest expense over the remaining lives of the underlying debt securities, which mature in June 2004 and January 2009, respectively.

     We received proceeds of $61.8 million, $38.3 million and $50.1 million from the issuance of common stock in 2003, 2002 and 2001, respectively, from the exercise of stock options and the issuance of stock through our employee stock purchase plan.

     During 2002, we were authorized by our Board of Directors to repurchase up to $275.0 million of our common stock. During 2003, we repurchased 6.3 million shares at an average price of $28.78 per share, for a total of $181.4 million. During 2002, we repurchased 1.8 million shares at an average price of $27.52 per share, for a total of $49.1 million. Upon repurchase, the shares were retired.

     We paid dividends of $154.3 million, $154.9 million and $154.4 million in 2003, 2002 and 2001, respectively.

Available Credit Facilities

     At December 31, 2003, we had $930.2 million of credit facilities with commercial banks, of which $500.0 million is a three–year committed revolving credit facility (the “facility”) that expires in July 2006. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility) of less than or equal to 0.50, limit the amount of subsidiary indebtedness and restrict the sale of significant assets, defined as 10% or more of total consolidated assets. At December 31, 2003, we were in compliance with all the facility covenants, including the funded indebtedness to total capitalization ratio, which was 0.30. There were no direct borrowings under the facility during the year ended December 31, 2003; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2003, we had no outstanding commercial paper.

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

Cash Requirements

     We believe operating cash flows combined with short–term borrowings, as needed, will provide us with sufficient capital resources and liquidity to manage our operations, meet contractual obligations, fund capital expenditures, repurchase common stock and support the development of our short–term and long–term operating strategies.

     We currently expect that 2004 capital expenditures will be between $320.0 million and $340.0 million, excluding acquisitions. The expenditures are expected to be used primarily for normal, recurring items necessary to support the growth of our business and operations.

     In 2004, we will repay the $100.0 million 8% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. These repayments are expected to be funded with one or more of the following: cash flows from operations, available cash on hand and commercial paper borrowings. In 2004, we also expect to make interest payments of approximately $85.0 million to $95.0 million. This is based on our current expectations of debt levels during 2004.

     We have authorization remaining to repurchase up to $44.5 million in common stock. We may continue to repurchase our common stock in 2004 depending on the price of our common stock, our liquidity and other considerations. We anticipate paying dividends of $0.46 per share of common stock in 2004. However, our Board of Directors is free to change the dividend policy at any time.

     During 2004, we estimate that we will contribute approximately $35.0 million to $40.0 million to our pension plans and make benefit payments related to postretirement welfare plans of approximately $14.0 million.

     We anticipate making income tax payments of approximately $150.0 million to $180.0 million in 2004.

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     We do not believe that there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than previously discussed, we currently have no information that would create a reasonable likelihood that the reported levels of revenues and cash flows from operations in 2003 are not indicative of what we can expect in the future.

     The following table summarizes our aggregate contractual cash obligations as of December 31, 2003 (in millions):

(1)		Amounts represent the expected cash payments for our long–term debt and do not include any unamortized discounts, deferred issuance costs or deferred gains on terminated interest rate swap agreements.
(2)		Purchase obligations include agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Purchase obligations exclude agreements that are cancelable at anytime without penalty.
(3)		Amounts represent other long–term liabilities reflected in our consolidated balance sheet where both the timing and amount of payment streams are known. Amounts include: payments for certain environmental remediation liabilities, payments for deferred compensation, payouts under acquisition agreements and payments for certain asset retirement obligations. Amounts do not include: payments for pension contributions and payments for various postretirement welfare plans and postemployment benefit plans, as such amounts have not been determined beyond 2004.

Off–Balance Sheet Arrangements

     In the normal course of business with customers, vendors and others, we are contingently liable for performance under letters of credit and other bank issued guarantees which totaled approximately $284.9 million at December 31, 2003. In addition, at December 31, 2003, we have guaranteed debt and other obligations of third parties totaling up to $34.1 million, including $15.0 million relating to Petreco. This guarantee was terminated in conjunction with the sale of Petreco in February 2004.

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

NEW ACCOUNTING STANDARDS

     Effective 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 of fair value 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 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.

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     In November 2002, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 45 (“FIN 45”), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 requires disclosures by a guarantor in its financial statements about obligations under certain guarantees that it has issued and requires a guarantor to recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The adoption of the provisions of FIN 45 relating to the initial recognition and measurement of guarantor liabilities, which were effective for qualifying guarantees entered into or modified after December 31, 2002, did not have an impact on our consolidated financial statements. We adopted the new disclosure requirements in 2002.

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

     In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which amends and clarifies the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with some exceptions for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 on July 1, 2003 had no impact on our consolidated financial statements.

     In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, which modifies the accounting for certain financial instruments. SFAS No. 150 requires that these financial instruments be classified as liabilities and applies immediately for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 on July 1, 2003 had no impact on our consolidated financial statements.

     In December 2003, the FASB revised SFAS No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits. The new SFAS No. 132 requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans, of which certain disclosures are not required until 2004. We have adopted the disclosure requirements that were effective for 2003.

     In January 2004, the FASB issued FASB Staff Position No. FAS 106–1 (“FSP 106–1”), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which provides temporary guidance concerning the recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”). SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, requires presently enacted changes in laws that will take effect in future periods to be taken into account in measuring current period postretirement benefit cost and the accumulated projected benefit obligation (“APBO”). FSP 106–1 allows companies that sponsor affected postretirement benefit plans to elect to defer recognizing the effects of the Act on postretirement benefit expense and on the APBO pursuant to SFAS No. 106. We have elected to defer accounting for the effects of the Act until 2004.

RELATED PARTY TRANSACTIONS

     In conjunction with the formation of WesternGeco in November 2000, we entered into an agreement with Schlumberger whereby a cash true–up payment will be made by either of the parties to the venture based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party will be required to make as a result of this adjustment is $100.0 million. In the event that future sales from the contributed libraries continue in the same relative percentages incurred through December 31, 2003, we currently estimate that Schlumberger will make a payment to us in the range of $5.0 million to $10.0 million. Any payment to be received by us will be recorded as an adjustment to the carrying value of our investment in WesternGeco. In November 2000, we also entered into an agreement with WesternGeco whereby WesternGeco subleased a facility from us for a period of ten years at then current market rates. In 2003 and 2002, we received payments of $5.0 million and $5.5 million, respectively, from WesternGeco related to this lease. In conjunction with the formation of WesternGeco, we transferred a lease on a seismic vessel to the venture. We were the sole guarantor of this lease obligation. During 2003, the lease and guarantee were terminated as a result of the purchase of the seismic vessel by WesternGeco.

     At December 31, 2003 and 2002, net accounts receivable from affiliates totaled $0.7 million and $16.1 million, respectively. There were no other significant related party transactions.

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FORWARD–LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Financial Statements include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “Forward–Looking Statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. Our expectations regarding our business outlook, customer spending, oil and natural gas prices and our business environment and the industry in general are only our forecasts regarding these matters. These forecasts may be substantially different from actual results, which are affected by the following risk factors: the level of petroleum industry exploration and production expenditures; drilling rig and oil and natural gas industry manpower and equipment availability; our ability to implement and effect price increases for our products and services; our ability to control our costs; the availability of sufficient raw materials, manufacturing capacity and subcontracting capacity at forecasted costs to meet our revenue goals; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; the ability of our competitors to capture market share; our ability to retain or increase our market share; potential impairment of long–lived assets; world economic conditions; the price of, and the demand for, crude oil and natural gas; drilling activity; seasonal and other weather conditions that affect the demand for energy and severe weather conditions, such as hurricanes, that affect exploration and production activities; the legislative and regulatory environment in the U.S. and other countries in which we operate; outcome of government and internal investigations and legal proceedings; OPEC policy and the adherence by OPEC nations to their production quotas; war, military action or extended period of international conflict, particularly involving the U.S., Middle East or other major petroleum–producing or consuming regions; any future acts of war, armed conflicts or terrorist activities; civil unrest or in–country security concerns where we operate; expropriation; the development of technology by us or our competitors that lowers overall finding and development costs; new laws and regulations that could have a significant impact on the future operations and conduct of all businesses; labor–related actions, including strikes, slowdowns and facility occupations; the condition of the capital and equity markets in general; adverse foreign exchange fluctuations and adverse changes in the capital markets in international locations where we operate; and the timing of any of the foregoing. See “Key Risk Factors” for a more detailed discussion of certain of these risk factors.

     Our expectations regarding our level of capital expenditures described in “Liquidity and Capital Resources” are only our forecasts regarding these matters. In addition to the factors described in the previous paragraph, in “Business Environment,” and in “Item 1. Business–Environmental Matters,” these forecasts may be substantially different from actual results, which are affected by the following factors: the accuracy of our estimates regarding our spending requirements; regulatory, legal and contractual impediments to spending reduction measures; the occurrence of any unanticipated acquisition or research and development opportunities; changes in our strategic direction; and the need to replace any unanticipated losses in capital assets.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

     We are exposed to certain market risks that are inherent in our financial instruments that arise in the normal course of business. We may enter into derivative financial instrument transactions to manage or reduce market risk but do not enter into derivative financial instrument transactions for speculative purposes. A discussion of our primary market risk exposure in financial instruments is presented below.

INDEBTEDNESS

     We are subject to interest rate risk on our long–term fixed interest rate debt. Commercial paper borrowings, other short–term borrowings and variable rate long–term debt do not give rise to significant interest rate risk because these borrowings either have maturities of less than three months or have variable interest rates. All other things being equal, the fair market value of debt with a fixed interest rate will increase as interest rates fall and will decrease as interest rates rise. This exposure to interest rate risk is managed by borrowing money that has a variable interest rate or using interest rate swaps to change fixed interest rate borrowings to variable interest rate borrowings.

     At December 31, 2003, we had fixed rate debt aggregating $1,425.6 million and variable rate debt aggregating $38.4 million. The following table sets forth, as of December 31, 2003 and 2002, the principal cash flow requirements for our indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the related weighted average effective interest rates by expected maturity dates (dollar amounts in millions).

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(1)		Fair market value of fixed rate long–term debt was $1,570.8 million at December 31, 2003 and $1,679.9 million at December 31, 2002.
(2)		Includes the effect of the amortization of deferred gains on terminated interest rate swap agreements.

INTEREST RATE SWAP AGREEMENTS

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

     During 2002, we terminated two interest rate swap agreements that had been entered into in prior years. These agreements had been designated and had qualified as fair value hedging instruments. Upon termination, we received proceeds totaling $15.8 million. The deferred gains of $4.8 million and $11.0 million are being amortized as a reduction of interest expense over the remaining lives of the underlying debt securities, which mature in June 2004 and January 2009, respectively.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

     We conduct operations around the world in a number of different currencies. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency. As such, future earnings are subject to change due to changes in foreign currency exchange rates when transactions are denominated in currencies other than our functional currencies. To minimize the need for foreign currency forward contracts to hedge this exposure, our objective is to manage foreign currency exposure by maintaining a minimal consolidated net asset or net liability position in a currency other than the functional currency.

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

     At December 31, 2002, we had entered into a foreign currency forward contract with a notional amount of $20.0 million to hedge exposure to fluctuations in the British Pound Sterling. The contract was a cash flow hedge. Based on year–end quoted market prices for contracts with similar terms and maturity dates, no asset or liability was recorded as the forward price was substantially the same as the contract price.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT REPORT OF FINANCIAL RESPONSIBILITIES

     The management of Baker Hughes Incorporated is responsible for the preparation and integrity of the accompanying consolidated financial statements and all other information contained in this annual report on Form 10–K. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles and include amounts that are based on management’s informed judgments and estimates.

     In fulfilling its responsibilities for the integrity of financial information, management maintains and relies on the Company’s system of internal control. This system includes written policies, an organizational structure providing division of responsibilities, the selection and training of qualified personnel and a program of financial and operational reviews by a professional staff of corporate auditors. The system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management’s authorization and accounting records are reliable as a basis for the preparation of the consolidated financial statements. The concept of reasonable assurance is based on the recognition that there are inherent limitations in all systems of internal control, and that the cost of such systems should not exceed the benefits to be derived there from. Management believes that, as of December 31, 2003, the Company’s internal control system provides reasonable assurance that material errors or irregularities will be prevented or detected within a timely period and is cost effective.

     Management has also established and maintains a system of disclosure controls designed to provide reasonable assurance that information required to be disclosed is accumulated and reported in an accurate and timely manner. A Disclosure Control and Internal Control Committee is in place to oversee this process and management believes that these controls are effective.

     Management recognizes its responsibility for fostering a strong ethical climate so that the Company’s affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company’s Business Code of Conduct which is distributed throughout the Company. Management maintains a systematic program to assess compliance with the policies included in the Business Code of Conduct.

     The Board of Directors, through its Audit/Ethics Committee composed solely of nonemployee directors, reviews the Company’s financial reporting, accounting and ethical practices. In 2003, the Audit/Ethics Committee engaged the Company’s independent public accountants, Deloitte & Touche LLP, and approved their fee arrangements. It meets periodically with the independent public accountants, management and the corporate auditors to review the work of each and the propriety of the discharge of their responsibilities. The independent public accountants and the corporate auditors have full and free access to the Audit/Ethics Committee, without management present, to discuss auditing and financial reporting matters.

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INDEPENDENT AUDITORS’ REPORT

Stockholders of Baker Hughes Incorporated:

     We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and its subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule II, valuation and qualifying accounts. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

     We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Baker Hughes Incorporated and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

     As described in Note 1 to the consolidated financial statements: effective as of January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, which established new accounting and reporting standards for asset retirement obligations; effective as of January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, which established new accounting and reporting standards for the recording, amortization and impairment of goodwill and other intangibles; and effective as of January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, as amended, which established new accounting and reporting standards for derivative instruments and hedging activities.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 11, 2004

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