UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

OR

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

     

Commission file number 1–9397

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

     Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES þ NO o

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. YES o NO þ

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

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non–accelerated filer.

Large accelerated filer þ		Accelerated filer o		Non–accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). YES o NO þ

     The aggregate market value of the voting and non–voting common stock held by non–affiliates as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing price on July 1, 2005 reported by the New York Stock Exchange) was approximately $17,495,000,000.

     As of February 24, 2006, the registrant has outstanding 342,267,907 shares of common stock, $1 par value per share.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of Registrant’s 2005 Proxy Statement for the Annual Meeting of Stockholders to be held April 27, 2006 are incorporated by reference into Part III of this Form 10–K.

 

 

Baker Hughes Incorporated

INDEX

				Page
Part I
Item 1.		Business			2
Item 1A.		Risk Factors			16
Item 1B.		Unresolved Staff Comments			19
Item 2.		Properties			19
Item 3.		Legal Proceedings			20
Item 4.		Submission of Matters to a Vote of Security Holders			21
Part II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			21
Item 6.		Selected Financial Data			23
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			42
Item 8.		Financial Statements and Supplementary Data			45
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			79
Item 9A.		Controls and Procedures			79
Item 9B.		Other Information			79
Part III
Item 10.		Directors and Executive Officers of the Registrant			79
Item 11.		Executive Compensation			79
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			80
Item 13.		Certain Relationships and Related Transactions			82
Item 14.		Principal Accounting Fees and Services			82
Part IV
Item 15.		Exhibits and Financial Statement Schedules			83
Retirement and Consulting Agreement
Form of Baker Hughes Incorporated Restricted Stock Award
Form of Baker Hughes Incorporated Stock Option Award Agreement
Form of Baker Hughes Incorporated Performance Unit Award Agreement
Performance Goals for Performance Unit Award
Compensation Table for Named Executive Officers and Directors
Subsidiaries of Registrant
Consent of Deloitte & Touche LLP
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Statement of CEO and CFO pursuant to Rule 13a-14b

PART I

     We have aggregated our divisions into these segments because they have similar economic characteristics and because their long-term financial performance is affected by similar economic conditions. They also operate in the same markets, which include all of the major oil and natural gas producing regions of the world. The results of each segment are evaluated regularly by our chief operating decision maker in deciding how to allocate resources and in assessing performance.

     For additional industry segment information for the three years ended December 31, 2005, see Note 13 of the Notes to Consolidated Financial Statements in Item 8 herein.

DRILLING AND EVALUATION SEGMENT

Baker Hughes Drilling Fluids

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

     Although technology is very important in the selection of drilling fluids for many drilling programs, cost efficiency tends to drive customer purchasing decisions. Specific opportunities for competitive differentiation include:

	•		improving drilling efficiency,
	•		minimizing formation damage, and
	•		handling and disposing of drilling fluids and cuttings in an environmentally safe manner.

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

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

Hughes Christensen

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

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

      PDC Bits. PDC (also known as “Diamond”) bits use fixed position cutters that shear the formation rock with a milling action as they are turned. In many softer and less variable applications, PDC bits offer higher penetration rates and a longer life than Tricone ^® bits. Advances in PDC technology have expanded the application of PDC bits into harder, more abrasive formations. A rental market has developed for PDC bits in the Western Hemisphere 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 International, Inc. (“Smith”), Grant Prideco, Inc., Halliburton and various other competitors.

     Key business drivers for Hughes Christensen include the number of drilling rigs operating, total footage drilled, drilling rig rental costs, as well as the current and expected future price of both oil and natural gas.

INTEQ

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

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

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

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

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

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

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

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

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

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

	•		the sophistication and accuracy of measurements,
	•		the efficiency of the drilling process (measured in cost per foot drilled),
	•		the reliability of equipment,
	•		the optimal placement of the wellbore in the reservoir, and
	•		the quality of the wellbore.

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

     Key business drivers for INTEQ include the number of drilling rigs operating, the total footage drilled, the mix of conventional and rotary steerable systems used, as well as the current and expected future price of both oil and natural gas.

Baker Atlas

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

      Formation Evaluation. Formation evaluation involves measuring and analyzing specific physical properties of the rock (petrophysical properties) in the immediate vicinity of a wellbore to determine an oil or natural gas reservoir’s boundaries, volume of hydrocarbons and ability to produce fluids to the surface. Electronic sensor instrumentation is run through the wellbore to measure porosity and density (how much open space there is in the rock), permeability (how well connected the spaces in the rock are) and resistivity (whether there is oil, natural gas or water in the spaces). Imaging tools are run through the wellbore to record a picture of the formation along the well’s length similar to a core sample. Acoustic logs measure rock properties and help correlate wireline data with previous seismic surveys. Magnetic resonance measurements characterize the volume and type of fluids in the formation as well as providing a direct measure of permeability. At the surface, measurements are recorded digitally and can be displayed on a continuous graph, or “well log,” which shows how each parameter varies along the length of the wellbore. Formation evaluation tools can also be used to record formation pressures and take samples of formation fluids to be further evaluated on the surface.

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

      Wireline Completion and Production Services. Wireline completion and production services include using wireline instruments to evaluate well integrity, perform mechanical intervention and perform cement evaluations. Wireline instruments can also be run in producing wells to perform production logging. Baker Atlas (and Baker Oil Tools) also provide perforating services, which involve puncturing a well’s steel casing and cement sheath with explosive charges. This creates a fracture in the formation and provides a path for hydrocarbons in the formation to enter the wellbore and be produced.

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

	•		the efficiency of data acquisition,
	•		the sophistication and accuracy of measurements,

	•		the ability to interpret the information gathered to quantify the hydrocarbons producible from the formation, and
	•		the ability to differentiate services that can run exclusively or more efficiently on wireline from services that can run on either wireline or drill pipe.

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

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

COMPLETION AND PRODUCTION SEGMENT

Baker Oil Tools

     Baker Oil Tools is a world leader in well completion and wellbore intervention solutions.

      Well Completion. The economic success of a well largely depends on how the well is completed. A successful completion ensures and optimizes the efficient and safe production of oil and natural gas to the surface. Baker Oil Tools’ completion systems are matched to the formation and reservoir for optimum production and can employ a variety of products and services including liner hangers, packers, flow control equipment, subsurface safety valves, sand control equipment and other advanced completion technologies.

     Liner hangers suspend a section of steel casing (also called a liner) inside the bottom of the previous section of casing. The liner hanger’s expandable slips grip the inside of the casing and support the weight of the liner below.

     Packers seal the annular space between the steel production tubing and the casing. These tools control the flow of fluids in the well and protect the casing above and below from reservoir pressures and corrosive formation fluids.

     Flow control equipment controls and adjusts the flow of downhole fluids. A common flow control device is a sliding sleeve, which can be opened or closed to allow or limit production from a particular portion of a reservoir. Flow control can be accomplished from the surface via wireline or downhole via hydraulic or electric motor-based automated systems.

     Subsurface safety valves shut off all flow of fluids to the surface in the event of an emergency, thus saving the well and preventing pollution of the environment. These valves are required in substantially all offshore wells.

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

     Advanced completion technologies include multilateral systems, intelligent well systems and expandable metal technologies. Multilateral completion systems enable two or more zones to be produced from a single well, using multiple horizontal branches. Intelligent Completions ^® use real-time, remotely operated downhole systems to control the flow of hydrocarbons from one or more zones. Expandable metal technology involves the permanent downhole expansion of a variety of tubular products used in drilling, completion and well remediation applications.

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

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

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

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

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

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

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

	•		engineering and manufacturing superior-quality products and providing solutions with a proven ability to reduce well construction costs,
	•		enhancing production and ultimate recovery,
	•		minimizing risks, and
	•		providing reliable performance over the life of the well, particularly in harsh environments and for critical wells.

     Baker Oil Tools’ primary competitors in well completion are Halliburton, Schlumberger, Weatherford and various other competitors. Its primary competitors in wellbore intervention are Halliburton, Schlumberger, Weatherford, Smith and various other competitors.

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

Baker Petrolite

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

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

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

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

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

     Corrosion inhibitors — Another problem caused by water mixed with downhole hydrocarbons is corrosion of the well’s tubulars and other production equipment. Corrosion can also be caused by dissolved hydrogen sulfide (“H ₂ S”) gas, which reacts with the iron

in tubulars, valves and other equipment, potentially causing failures and leaks. Additionally, the reaction creates iron sulfide, which can impair treating systems and cause blockages. Baker Petrolite offers a variety of corrosion inhibitors and H ₂ S scavengers.

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

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

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

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

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

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

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

Centrilift

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

      Electrical Submersible Pump Systems. ESPs lift 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 variable speed controller at the surface. Centrilift designs, manufactures, markets and installs all the components of ESP systems and also offers modeling software to size ESPs and simulate operating performance. ESPs may be used in both onshore or offshore wells. The range of appropriate application of ESP systems is expanding as technology and reliability enhancements have improved ESP system performance in harsher environments and marginal reservoirs.

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

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

	•		the ability to lift fluids of differing physical properties and chemical compositions,
	•		system reliability and run life,
	•		the ability of the system to optimize production,
	•		operating efficiency, and
	•		service delivery.

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

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

Production Optimization

     The Production Optimization business unit is a leading provider of permanent monitoring systems and chemical automation systems.

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

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

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

	•		the ability to provide application engineering and economic return analysis,
	•		innovative products,
	•		gauge measurement accuracy,
	•		product life and performance, and
	•		installation and service capabilities.

     Production Optimization’s primary competitors are Schlumberger, Halliburton and Weatherford.

     Key business drivers for Production Optimization include the level of oil and gas prices, total daily oil and gas production and capital spending for critical wells (offshore, sub-sea, high production on-shore and remotely located on-shore).

WesternGeco

     WesternGeco is a seismic venture in which we own 30% and Schlumberger owns 70%. WesternGeco provides comprehensive worldwide reservoir imaging, monitoring and development services. The venture provides these services through its extensive

number of seismic crews and data processing centers, as well as through its ownership of one of the world’s largest multiclient seismic libraries. Services range from 3D and time-lapse (4D) seismic surveys to multicomponent surveys for delineating prospects and reservoir management. WesternGeco is positioned to meet the full range of customer needs in land, marine and shallow-water transition-zone areas.

     Seismic solutions include proprietary Q-Technology* for enhanced reservoir description, characterization and monitoring throughout the life of the field — from exploration through enhanced recovery.

     WesternGeco’s Omega* Seismic Processing System encompasses one of the industry’s most advanced and comprehensive suites of algorithms and runs on multiplatform technology, ensuring timely turnaround for even the most complex processing projects.

     WesternGeco’s major competitors are Compagnie Generale de Geophysique, Veritas DGC, Inc. and Petroleum Geo-Services ASA.

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

* Mark of WesternGeco

MARKETING, COMPETITION AND ECONOMIC CONDITIONS

     We market our products and services on a product line basis primarily through our own sales organizations, although certain of our products and services are marketed through supply stores, independent distributors, agents, licensees or sales representatives. We ordinarily provide technical and advisory services to assist in our customers’ use of our products and services. Stock points and service centers for our products and services are located in areas of drilling and production activity throughout the world.

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

     Further information is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

INTERNATIONAL OPERATIONS

     We operate in over 90 countries worldwide, and our operations are subject to the risks inherent in doing business in multiple countries with various laws and differing political environments. These risks include the risks identified in “Item 1A. Risk Factors.” Although it is impossible to predict the likelihood of such occurrences or their effect on us, division and corporate management routinely evaluate these risks and take appropriate actions to mitigate the risks where possible. However, there can be no assurance that an occurrence of any one or more of these events would not have a material adverse effect on our operations.

     Further information is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

RESEARCH AND DEVELOPMENT; PATENTS

     We are engaged in research and development activities directed primarily toward the improvement of existing products and services, the design of specialized products to meet specific customer needs and the development of new products, processes and services. For information regarding the amounts of research and development expense in each of the three years in the period ended December 31, 2005, 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. Although, patent and trademark

protection is important to our business and future prospects, we consider the reliability and quality of our products and the technical skills of our personnel to be more important. No single patent or trademark is considered to be critical to our business.

RAW MATERIALS

     We purchase various raw materials and component parts for use in manufacturing our products. The principal materials we purchase are steel alloys (including chromium and nickel), titanium, beryllium, copper, tungsten carbide, synthetic and natural diamonds, printed circuit boards and other electronic components and hydrocarbon-based chemical feed stocks. These materials are generally available from multiple sources and could be subject to rising costs. We have not experienced significant shortages of these materials and normally do not carry inventories of such materials in excess of those reasonably required to meet our production schedules. We do not expect significant interruptions in supply, but there can be no assurance that there will be no price or supply issues over the long term.

OTHER DEVELOPMENTS

     In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“SPD”), a product line group within the Baker Oil Tools division of the Completion and Production segment. SPD distributes basic supplies, products and small tools to the drilling industry. In January 2006, we signed a non–binding letter of intent for the sale of SPD. The sale is expected to close in the first quarter of 2006. We have reflected SPD as a discontinued operation in the consolidated financial statements. SPD had revenues of $32.5 million for the year ended December 31, 2005. This transaction is subject to the negotiation and execution of a definitive sale agreement, as well as, various conditions, including satisfactory due diligence review of SPD’s business. There can be no assurance that the transaction will be consummated.

     In December 2005, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million in cash, which is included in the Baker Oil Tools division of the Completion and Production segment. As a result of the acquisition and based on preliminary estimates of fair values, we recorded approximately $19.5 million of goodwill and intangible assets, which may be revised based on the final purchase price allocations. The purchase price was preliminarily allocated based on the fair values of the assets acquired and liabilities assumed in the acquisition. Under the terms of the Purchase Agreement, the former owners of Zertech are entitled to additional purchase price consideration of up to approximately $14.0 million based on the performance of the business during 2006, 2007 and 2008.

     In October 2005, we finalized the purchase of the remaining 50% interest in QuantX Wellbore Instrumentation venture (“QuantX”), a venture engaged in permanent in–well monitoring, for $27.2 million, subject to final purchase price adjustments. QuantX is included in the Production Optimization business unit of the Completion and Production segment. Based on our carrying value of our existing investment in QuantX of $35.5 million and the additional consideration of $27.2 million, we recorded approximately $28.4 million of goodwill and $19.6 million of intangibles. We also assigned $5.1 million to in–process research and development that was written off at the date of acquisition. The purchase price was allocated based on the fair value of the assets acquired and liabilities assumed of QuantX. The fair values were determined using a discounted cash flow approach.

     In January 2006, we acquired Nova Technology Corporation (“Nova”) for approximately $67.0 million in cash and assumed debt. Nova is a leading supplier of permanent monitoring, chemical injection systems, and multi–line services for deepwater and subsea oil and gas well applications and will be included in the Production Optimization business unit of the Completion and Production segment.

EMPLOYEES

     On December 31, 2005, we had approximately 29,100 employees, as compared with approximately 26,900 employees on December 31, 2004. Approximately 2,590 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.

     There are no family relationships among our executive officers.

ENVIRONMENTAL MATTERS

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

     We are involved in voluntary remediation projects at some of our present and former manufacturing facilities, the majority of which relate to properties obtained in acquisitions or to sites no longer actively used in operations. On rare occasions, remediation activities are conducted as specified by a government agency–issued consent decree or agreed order. Remediation costs are accrued based on estimates of probable exposure using currently available facts, existing environmental permits, technology and presently enacted laws and regulations. For sites where we are primarily responsible for the remediation, our cost estimates are developed based

on internal evaluations and are not discounted. Such accruals are recorded when it is probable that we will be obligated to pay amounts for environmental site evaluation, remediation or related activities, and such amounts can be reasonably estimated. If the obligation can only be estimated within a range, we accrue the minimum amount in the range. Such accruals are recorded even if significant uncertainties exist over the ultimate cost of the remediation. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal, are expensed as incurred.

     During the year ended December 31, 2005, we spent approximately $32.1 million to comply with domestic and international standards regulating the discharge of materials into the environment or otherwise relating to the protection of the environment (collectively, “Environmental Regulations”). This cost includes the total spent on remediation projects at current or former sites, Superfund projects and environmental compliance activities, exclusive of capital. In 2006, we expect to spend approximately $34.2 million to comply with Environmental Regulations. Based upon current information, we believe that our compliance with Environmental Regulations will not have a material adverse effect upon our capital expenditures, earnings or competitive position because we have either established adequate reserves or our cost for that compliance is not expected to be material to our consolidated financial statements.

     During the year ended December 31, 2005, we incurred approximately $3.8 million in capital expenditures for environmental control equipment, and we estimate we will incur approximately $6.3 million during 2006. We believe these capital expenditures for environmental control equipment will not have a material adverse effect upon our consolidated financial statements.

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

     We have been identified as a PRP at various Superfund sites discussed below. The United States Environmental Protection Agency (the “EPA”) and appropriate state agencies supervise investigative and cleanup activities at these sites. For the year ended December 31, 2005, we paid $0.5 million in superfund costs and have accrued an additional $4.9 million related to these sites. Payments made in 2005 are in addition to amounts previously paid in settlements, cash calls or other superfund costs, and these ongoing contributions reduce our financial liability for the total site cleanup costs shown below. When used in the descriptions of the sites that follow, the word de minimis refers to the smallest PRPs, whose contribution rate is usually less than 1%.

	(a)		Baker Petrolite, Hughes Christensen, an INTEQ predecessor entity, Baker Oil Tools and a former subsidiary were named in April 1984 as PRPs at the Sheridan Superfund Site located in Hempstead, Texas. The Texas Commission on Environmental Quality (“TCEQ”) is overseeing the remedial work at this site. The Sheridan Site Trust was formed to manage the site remediation and we participate as a member. Based on the use of new remedial technologies, the cost projections remain at $6.0 million for full remediation, of which $5.5 million has been collected. Our additional contribution is approximately 1.8% of the remaining costs.
	(b)		In 1997, we entered into a settlement agreement with Prudential Insurance Company (“Prudential”) regarding cost recovery for the San Fernando Valley — Glendale Superfund. One of our predecessors operated on the Prudential property in Glendale. After Prudential was identified as a PRP for the Glendale Superfund, they instituted legal proceedings against us for cost recovery under CERCLA. Without any admission of liability, we agreed to pay 40% of Prudential’s costs attributed to cleanup at the site, limited to a cap of $0.3 million. A pump and treat system was selected as the cleanup remedy at Glendale, and it is expected to operate until 2012. We continue to contribute our portion of ongoing assessments to fund this remediation strategy.
	(c)		In 1999, the EPA named a Hughes Christensen predecessor as a PRP at the Li Tungsten Site in Glen Cove, New York. We contributed a de minimis amount of hazardous substances to the site. In December 2004, the EPA issued us a special de minimis settlement offer based on the fact that our contribution was limited to metals contamination, not radiological contamination, at the site. We expect to settle this matter with the EPA for less than $0.1 million.
	(d)		In 1999, Baker Oil Tools, Baker Petrolite and predecessor entities of Baker Petrolite were named as PRPs by the State of California’s Department of Toxic Substances Control for the Gibson site in Bakersfield, California. The most recent cost estimate for remediation of the site is $17.9 million. The combined volume that we contributed to the site is estimated to be less than 0.5% for liquids and 0.25% for solids.

	(e)		In 2001, a Hughes Christensen predecessor, Baker Oil Tools, INTEQ and one of our former subsidiaries were named as PRPs in the Force Road State Superfund Site located in Brazoria County, Texas. The TCEQ is overseeing the investigation and remediation at the Force Road State Site. We participate as a member of the steering and technical committees to effectively manage the project because our volumetric contribution is currently estimated at approximately 76%. The onsite investigation was completed in late 2005, while the offsite investigation is pending access to the adjacent property. The estimate of site remediation costs used for initial settlement purposes was $17.7 million; however, we anticipate that a more accurate calculation of site remediation costs will be possible once the offsite investigation is complete. We believe that after further investigation at the site, negotiation of additional early settlements with other PRPs, future cost recovery actions against recalcitrant parties and other factors, our ultimate share of responsibility for cleanup costs at the site will be less than initial estimates.
	(f)		In 2002, Baker Petrolite predecessors, Hughes Christensen predecessors and two of our former subsidiaries were identified as PRPs for the Malone site located on Campbell Bayou Road in Texas City, Texas. The EPA oversees the investigation and remediation of the Malone site and has engaged in emergency removal actions. The investigation is nearly complete and in 2006, remedial options are expected to be developed and submitted to the EPA for evaluation. The estimate for cleanup at the Malone site is $82 million with our contribution estimated at approximately 1.7%. The current owners of the site have filed a lawsuit against the PRPs seeking recovery of certain alleged damages, which may affect the ultimate resolution of this superfund.
	(g)		In 2003, Western Atlas International, Inc., its predecessor companies and Baker Hughes Oilfield Operations, Inc. were identified as de minimis PRPs in the Gulf Nuclear Superfund site in Odessa, Texas. The EPA conducted an emergency removal at the site in 2000. Total investigation and cleanup costs were estimated by the EPA to be approximately $24 million. The de minimis settlement proposal has been negotiated and should be finalized in 2006. Our settlement cost is expected to be less than $0.1 million.
	(h)		In 2003, we were identified as a de minimis PRP by the EPA for the Operating Industries, Inc. Superfund site in Monterrey Park, California. A settlement offer to all remaining de minimis parties has been repeatedly delayed, but is expected in mid 2006. The EPA and Steering Committee estimate cleanup costs in excess of $650 million. As of January 2006, there was insufficient information to estimate our allocation or potential contribution to these cleanup costs.
	(i)		In 2003, Baker Petrolite was notified by the EPA of their potential involvement at the Cooper Drum Superfund site located in South Gate, California. The company responded to an additional inquiry from the EPA in 2005. At this time there is no estimate available for comprehensive cleanup costs or our allocation and, accordingly, the extent of our financial liability at the site is unknown.
	(j)		In 2004, we were notified that Baker Petrolite was included in the Container Recycling Superfund site in Kansas City, Kansas. We are a PRP at the site, which was a former drum recycler used by a predecessor company to Baker Petrolite. Site remediation has been completed and the EPA has extended a settlement offer of $1.3 million to the PRP group with our allocation calculated at 4% of these costs. Baker Petrolite has signed the settlement offer.
	(k)		In 2005, Centrilift was notified by the TCEQ of their potential involvement in the San Angelo Superfund site in Tom Green County, Texas. Polychlorinated biphenyls (PCBs) are present at the site as a result of the operations of the former San Angelo Electric Services Company (SESCO), which manufactured, repaired and serviced transformers. SESCO declared bankruptcy in mid 2003, after which the TCEQ conducted emergency removal actions in response to reports of contamination onsite and in the adjacent residential area. A de minimis settlement offer has been received, and our cost contribution for the remediation of soil and groundwater is less than $0.1 million.

     In addition to the sites mentioned above, there are four Superfund sites where we have ongoing obligations. The remedial work at most of these sites has been completed and remaining operations are limited to groundwater recovery and/or monitoring. The monitoring phase can continue for up to 30 years. Our aggregate cost for these sites is estimated to be 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 consolidated financial statements because we have established adequate reserves to cover the estimate we presently believe will be our ultimate liability in the matter. Further, other PRPs involved in the sites have

substantial assets and may reasonably be expected to pay their share of the cost of remediation, and, in some circumstances, we have insurance coverage or contractual indemnities from third parties to cover a portion of or the ultimate liability.

     We are subject to various other governmental proceedings and regulations, including foreign regulations, relating to environmental matters, but we do not believe that any of these matters is likely to have a material adverse effect on our consolidated financial statements. We continue to focus on reducing future environmental liabilities by maintaining appropriate company standards and improving our assurance programs. See Note 16 of the Notes to Consolidated Financial Statements in Item 8 herein for further discussion of environmental matters.

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

ITEM 1A. RISK FACTORS

     An investment in our common stock involves various risks. When considering an investment in our company, you should consider carefully all of the risk factors described below, as well as other information included and incorporated by reference in this report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

     Our business is focused on providing products and services to the worldwide oil and natural gas industry; therefore, our risk factors include those factors that impact, either positively or negatively, the markets for oil and natural gas. Expenditures by our customers for exploration, development and production of oil and natural gas are based on their expectations of future hydrocarbon demand, the risks associated with developing the reserves and the future value of the hydrocarbon reserves. Their evaluation of the future value is based, in part, on their expectations for global demand, global supply and other factors that influence oil and natural gas prices. The key risk factors currently influencing the worldwide oil and natural gas markets are discussed below.

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

     Growth in worldwide demand for oil and natural gas, as well as the demand for our services, is highly correlated with global economic growth — and in particular by the economic growth of countries such as the U.S. and China, who are significant users of oil and natural gas. Increases in global economic activity, particularly in China and developing Asia, create more demand for oil and natural gas and higher oil and natural gas prices. A slowing of global economic growth, and in particular in the U.S. or China, will likely reduce demand for oil and natural gas, increase excess productive capacity and result in lower prices and adversely impact the demand for our services.

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

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

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

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

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

     Supply can be interrupted by a number of factors including political instability, civil unrest, labor issues, terrorist attacks, war or military activity. Key oil producing countries which could be subject to supply interruptions include, but are not limited to, Saudi Arabia, Iran, Iraq and other Middle Eastern countries, Nigeria, Norway, Russia and Venezuela. The impact of supply and demand disruptions on oil and natural gas prices and oil and natural gas price volatility is tempered by the size and expected duration of the disruption relative to the excess productive capacity at the time of the disruption.

     Supply can also be impacted by the degree to which individual Organization of Petroleum Exporting Countries (“OPEC”) nations and other large oil and natural gas producing countries, including, but not limited to, 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. Any of these factors could affect the supply of oil and natural gas and could have a material adverse effect on our results of operations.

Excess productive capacity and future demand impact our operations.

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

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

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

Risk Factors Related to Our Business

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

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

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

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

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

The high cost or unavailability of materials, equipment, supplies and personnel could adversely affect our ability to execute our operations on a timely basis.

     Our manufacturing operations are dependent on having sufficient raw materials, component parts and manufacturing capacity available to meet our manufacturing plans at a reasonable cost while minimizing inventories. Our ability to effectively manage our manufacturing operations and meet these goals can have an impact on our business, including our ability to meet our manufacturing plans and revenue goals, control costs and avoid shortages of raw materials and component parts. Raw materials and components of particular concern include steel alloys, copper, carbide, chemicals and electronic components. Our ability to repair or replace equipment damaged or lost in the well can also impact our ability to service our customers.

     People are a key resource to developing, manufacturing and delivering our products and services to our customers around the world. Our ability to recruit, train and retain the highly skilled workforce required by our plans will impact our business. A well-trained, motivated work force has a positive impact on our ability to attract and retain business. Rapid growth presents a challenge to us and our industry to recruit, train and retain our employees while managing the impact of wage inflation and potential lack of available qualified labor in the markets where we operate. Labor-related actions, including strikes, slowdowns and facility occupations can also have a negative impact on our business.

Compliance with and changes in laws and regulations and risks from investigations and legal proceedings could be costly and could adversely affect operating results.

     Our operations in the U.S. and over 90 countries can be impacted by expected and unexpected changes in the legal and business environments in which we operate, as well as the outcome of ongoing government and internal investigations and legal proceedings.

     Changes that could impact the legal environment include new legislation, new regulation, new policies, investigations and legal proceedings and new interpretations of the existing legal rules and regulations. In particular, changes in export control laws or exchange control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in Russia or other countries identified by management for immediate focus. Changes that impact the business environment include changes in accounting standards, changes in environmental laws, changes in tax laws or tax rates, the resolution of audits by various tax authorities, and the ability to fully utilize our tax loss carryforwards and tax credits. Compliance related issues could limit our ability to do business in certain countries.

     These changes could have a significant financial impact on our future operations and the way we conduct, or if we conduct, business in the affected countries.

Uninsured claims and litigation could adversely impact our operating results.

     We have insurance coverage against operating hazards, including product liability claims and personal injury claims related to our products, to the extent deemed prudent by our management and to the extent insurance is available, 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 claims and litigation. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. Whenever possible, we obtain agreements from customers that limit our liability. Insurance and customer agreements do not provide complete protection against losses and risks, and our results of operations could be adversely affected by unexpected claims not covered by insurance.

Compliance with and rulings and litigation in connection with environmental regulations may adversely affect our business and operating results.

     Our business is impacted by unexpected outcomes or material changes in environmental liability. Changes in our environmental liability could originate with the discovery of new environmental remediation sites, changes in environmental regulations, or the discharge of hazardous materials or oil and natural gas into the environment.

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

     Fluctuation in foreign currencies relative to the U.S. Dollar can impact our costs of doing business. Most of our products and services are sold through contracts denominated in U.S. Dollars or local currency indexed to U.S. Dollars. Local expenses and some of our manufacturing costs are incurred in local currencies and therefore changes in the exchange rates between the U.S. Dollar and foreign currencies, particularly the British Pound Sterling, Euro, Canadian Dollar, Norwegian Krone, Venezuelan Bolivar, Australian Dollar and Brazilian Real, can increase or decrease our U.S. Dollar expenses and impact our operating margins. The majority of our significant foreign subsidiaries have designated the local currency as their functional currency and, as such, gains and losses resulting from balance sheet translation of foreign operations are included as a separate component of accumulated other comprehensive loss within stockholders’ equity. Gains and losses from foreign currency transactions, such as those resulting from the settlement of receivables or payables in the non–functional currency, are included in the consolidated statements of operations as incurred. For those foreign subsidiaries that have designated the U.S. Dollar as the functional currency, gains and losses resulting from balance sheet translation of foreign operations are also included in the consolidated statements of operations as incurred. Such transaction and translation losses may adversely impact our results of operations.

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

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

The market price of our common stock may fluctuate.

     Historically, the market price of common stock of companies engaged in the oil and natural gas industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past. News announcements and changes in oil and natural gas prices, changes in the demand for oil and natural gas exploration and changes in the supply and demand for oil and natural gas have all been factors that have affected the price of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     None.

ITEM 3. LEGAL PROCEEDINGS

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

     On September 12, 2001, we, without admitting or denying the factual allegations contained in the Order, consented with the 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 us in violation of Section 13(b)(2)(B) because we did not have a system of internal controls to determine if payments violated the Foreign Corrupt Practices Act (“FCPA”). The FCPA makes it unlawful for U.S. issuers, including us, or anyone acting on their behalf, to make improper payments to any foreign official in order to obtain or retain business. In addition, as discussed below, the FCPA establishes accounting and internal control requirements for U.S. issuers. We cooperated with the SEC’s investigation.

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

     On March 29, 2002, we announced that we had been advised that the SEC and the DOJ 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 Foreign Corrupt Practices Act (“FCPA”) regarding anti–bribery, books and records and internal controls. The SEC has issued subpoenas seeking information about our operations in Angola (subpoena dated August 6, 2003) and Kazakhstan (subpoenas dated August 6, 2003 and April 22, 2005) as part of its ongoing investigation. We are providing documents to and cooperating fully with the SEC and DOJ. The DOJ and the SEC have issued subpoenas to, or otherwise asked for interviews with, current and former employees in connection with the investigations regarding Nigeria, Angola and Kazakhstan. In addition, we have conducted internal investigations into these matters.

     Our internal investigations have identified issues regarding the propriety of certain payments and apparent deficiencies in our books and records and internal controls with respect to certain operations in Nigeria, Angola and Kazakhstan, as well as potential liabilities to governmental authorities in Nigeria. The internal investigation in Nigeria was substantially completed during the first quarter of 2003, and, based upon current information, we do not expect that any such potential liabilities will have a material adverse effect on our consolidated financial statements. The internal investigations in Angola and Kazakhstan were substantially completed in the third quarter of 2004. Evidence obtained during the course of the internal investigations has been provided to the SEC and DOJ.

     The Department of Commerce, Department of the Navy and DOJ (the “U.S. agencies”) have investigated 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. WesternGeco continued to use the licenses until 2001. Under the WesternGeco Formation Agreement, we owe indemnity to WesternGeco for certain matters and, accordingly, we have agreed to indemnify WesternGeco with certain limitations in connection with this matter. We are cooperating fully with the U.S. agencies.

     We have received a subpoena from a grand jury in the Southern District of New York regarding goods and services we delivered to Iraq from 1995 through 2003 during the United Nations Oil–for–Food Program. We have also received a request from the SEC to provide a written statement and certain information regarding our participation in that program. We have responded to both the subpoena and the request and may provide additional information and documents in the future. Other companies in the energy industry are believed to have received similar subpoenas and requests.

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

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

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

ITEM 6. SELECTED FINANCIAL DATA

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

NOTES TO SELECTED FINANCIAL DATA

     During 2005, the Baker Hughes worldwide rig count continued to increase, as oil and natural gas companies around the world recognized the need to build productive capacity to meet the growing demand for hydrocarbons and to offset depletion of existing developed reserves. Oil and natural gas prices were at historic highs in 2005, reflecting continued strong demand, relatively low excess productive capacity, and disruptions in supply due to hurricanes in the Gulf of Mexico. We reported revenues of $7,185.5 million for 2005, an 18.2% increase compared with 2004, approximating the 14.8% increase in the worldwide average rig count for 2005 compared with 2004. In addition to the growth in our revenues from increased activity, our revenues were impacted by pricing improvements and changes in market share in certain product lines. Net income for 2005 was $878.4 million, a 66.2% increase compared with $528.6 million in 2004.

	•		North American revenues increased 20.9% in 2005 compared with 2004, while the rig count increased 18.0% for 2005 compared with 2004, driven primarily by land-based drilling for natural gas. In 2005, hurricane-related disruptions negatively impacted our revenues from the U.S. offshore market by approximately $68.0 million.
	•		Latin American revenues increased 15.3% and the Latin American rig count increased 9.0% in 2005 compared with 2004.
	•		Europe, Africa, Russia and the Caspian revenues increased 14.0% in 2005 compared with 2004. Growth in revenues from Europe and Africa exceeded the increase in the rig counts for both regions for the comparable periods.
	•		Middle East and Asia Pacific revenues were up 20.2% in 2005 compared with 2004. Revenue from the Middle East was up 20.5% compared to a rig count which increased 7.4% and Asia Pacific revenue was up 20.0% compared to a rig count which increased 14.2%.

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

     The primary driver of our business is our customers’ capital and operating expenditures dedicated to exploring and drilling for and developing and producing oil and natural gas. Our business is cyclical and is dependent upon our customers’ forecasts of future oil and natural gas prices, future economic growth and hydrocarbon demand and estimates of future oil and natural gas production. During 2005, our customers’ spending directed to both worldwide oil and North American oil and natural gas projects increased compared with 2004. The increase in spending was driven by the multi-year requirement to find, develop and produce more hydrocarbons to meet the growth in demand, offset production declines, increase inventory levels and rebuild productive capacity. Additionally, the increase was supported by historically high oil and natural gas prices. Our customers’ spending on oil and gas projects is expected to continue to grow through 2006.

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

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

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

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

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

     The execution of our 2006 business plan and the ability to meet our 2006 financial objectives are dependent on a number of factors. These factors include, but are not limited to, our ability to: recruit, train and retain the skilled and diverse workforce necessary to meet our business needs; realize price increases commensurate with the value we provide to our customers and in excess of the increase in raw material and labor costs; expand our business in areas that are growing rapidly with customers whose spending is expected to increase substantially (such as NOCs), and in areas where we have market share opportunities (such as the Middle East, Russia and the Caspian region); manage increasing raw material and component costs (especially steel alloys, copper, carbide, chemicals and electronic components); continue to make ongoing improvements in the productivity of our manufacturing organization.

     For a full discussion of risk factors and forward-looking statements, please see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein.

BUSINESS ENVIRONMENT

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

Rig Counts

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

     Rigs in the U.S. 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, which may change from time to time and may vary from region to region, and is expected to be a potential consumer of our drill bits. In general, rigs are counted as active if the well has been started but has not reached its target depth, even if there are extensive delays due to weather or other reasons. If the well has been started but not completed and the rig is expected to resume work in two weeks or less, the rig is counted as active during a weather delay. Rigs are not typically counted as active if the rig is lost or damaged or if drilling operations are expected to be suspended for more than two weeks.

     Rigs in Canada are counted as active if data obtained by the Canadian Association of Oilwell Drillers and Contractors indicates that drilling operations have occurred during the week and we are able to verify this information. In most other international areas, rigs are counted as active if drilling operations have taken place for at least 15 days during the month. In some active international areas where better data is available, a weekly or daily average of active rigs is taken. In those international areas where there is poor availability of data, the rig counts are estimated or quoted from third party data.

     The rig count does not include rigs that are in transit from one location to another, are rigging up, are being used in non-drilling activities, including production testing, completion and workover, or are not, in our opinion, deemed to be a potential user of our drill bits.

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

          The U.S. land and inland waters rig count increased 17.8% in 2005 compared with 2004, due to the increase in drilling for natural gas. The U.S. offshore rig count decreased 4.1% in 2005 compared with 2004, reflecting the activity disruptions caused by hurricanes in the Gulf of Mexico in the third quarter of 2005. The Canadian rig count increased 24.7% due to the increase in drilling for natural gas.

     Outside North America, the rig count increased 8.6% in 2005 compared with 2004. The rig count in Latin America increased 9.0% in 2005 compared with 2004, driven primarily by activity increases in Venezuela, Colombia and Argentina. The North Sea rig count increased 10.3% in 2005 compared with 2004. The rig count in Africa increased by 2.0% in 2005 compared with 2004. Activity in the Middle East continued to rise steadily, with a 7.4% increase in the rig count in 2005 compared with 2004, driven primarily by activity increases in Saudi Arabia, Qatar, Sudan and Yemen. The rig count in the Asia Pacific region was up 14.2% in 2005 compared with 2004, primarily due to activity increases in India, Indonesia, offshore China and Thailand.

Oil and Natural Gas Prices

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

     Oil prices averaged a historic high of $56.59/Bbl in 2005. Prices increased from the low $40s/Bbl in January 2005 to a high of almost $70/Bbl in late September 2005, before moderating and ending the year in the low $60s/Bbl. Between mid-August and the end of September oil prices traded between $60/Bbl and $70/Bbl primarily due to the disruptive impact of hurricanes in the Gulf of Mexico. Worldwide demand for hydrocarbons was driven by strong worldwide economic growth, which was particularly strong in China and developing Asia. Worldwide excess productive capacity was at the lowest level in 30 years, and disruptions, or the potential for disruptions, in oil supply resulted in volatile oil prices throughout the year.

     During 2005, natural gas prices averaged a historic high of $8.66/mmBtu. Throughout the first seven months of 2005, a tight balance between supply and demand supported prices between $5.50/mmBtu and $8/mmBtu. In the last five months of 2005, natural gas was extremely volatile trading between $9/mmBtu and $15/mmBtu due to supply disruptions caused by Gulf of Mexico hurricanes and supported by high oil prices.

Worldwide Oil and Natural Gas Industry Outlook

     This section should be read in conjunction with the factors described in the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” and the “Risk Factors Related to Our Business” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein. These factors could impact, either positively or negatively, our expectation for oil and natural gas demand, oil and natural gas prices and drilling activity.

      Oil — Average oil prices in 2006 are expected to be between $55/Bbl and $75/Bbl. Strong worldwide economic growth and the lack of excess productive capacity are expected to support prices within this range. Growth in oil demand is expected to increase in 2006 compared with 2005, as worldwide economic growth and, in particular, economic growth in China is expected to continue to grow in 2006. At the beginning of December 2005, the International Energy Agency estimated that excess productive capacity was less than 3% of demand and that more than three-quarters of the excess capacity was in Saudi Arabia and Iraq. The ongoing lack of excess productive capacity will leave the energy markets susceptible to price volatility and the Organization of Petroleum Exporting Countries (“OPEC”) is unlikely to be able to rapidly increase production should there be any significant disruptions or threat of disruptions in oil supplies.

     Factors that could lead to prices at the lower end of this range include, but are not limited to: (1) a significant slowing of worldwide economic growth, particularly economic growth in China; (2) increases in Russian oil exports; (3) any significant disruption to demand; or (4) other factors that result in excess productive capacity and higher oil inventory levels or decreased demand. Factors that could lead to prices at the higher end of this range include, but are not limited to: (1) more rapid than planned expansion of the worldwide economy, particularly the economy in China; (2) a significant slowing of exports from Russia and the inability of key exporting countries to produce additional crude; or (3) other factors that result in excess productive capacity remaining at low levels.

     Factors that could lead to disruptions or the threat of disruptions in oil supply and volatility in oil prices include, but are not limited to: (1) terrorist attacks targeting oil production from Saudi Arabia or other key producers; (2) labor strikes in key oil producing areas such as Nigeria; (3) the potential for other military actions in the Middle East; or (4) adverse weather conditions, especially in the Gulf of Mexico. The potential for these and other events to cause volatility will be mitigated by the degree to which OPEC and, in particular, Saudi Arabia are able to increase excess productive capacity as well as the capability of the markets to refine and market products refined from crude oil.

      Natural Gas — Natural gas prices in 2006 are expected to remain volatile, averaging between $6/mmBtu and $15/mmBtu. A significant factor for the markets will be the pace of recovery of production of natural gas in the Gulf of Mexico following the disruptions from hurricanes in the Gulf of Mexico in 2005.

     Natural gas prices could trade at the top, or beyond the top, of this range if: (1) storage levels are relatively low at the beginning of the withdrawal season; (2) winter weather is colder than normal or summer weather is warmer than normal; (3) we experience slower than expected restoration of hurricane damaged production facilities; or (4) the U.S. economy, particularly the industrial sector, exhibits greater than expected growth and continued levels of oilfield customer spending are not sufficient to support the production growth required to meet the growth of natural gas demand. Natural gas prices could move to the bottom, or below the bottom, of this range if: (1) storage levels are relatively high at the beginning of the injection season; (2) U.S. economic growth is weaker than expected; or (3) weather is milder than expected.

      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 — Customer spending in North America, primarily towards developing natural gas supplies, is expected to increase approximately 18% to 22% in 2006 compared with 2005.
	•		Outside North America — Customer spending, primarily directed at developing oil supplies, is expected to increase approximately 16% to 20% in 2006 compared with 2005.
	•		Total spending is expected to increase approximately 17% to 21% in 2006 compared with 2005.

      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:

•

Drilling activity in North America is expected to increase approximately 12% to 14% in 2006 compared with 2005.

•

Drilling activity outside of North America is expected to increase approximately 8% to 10% in 2006 compared with 2005, excluding Iran and Sudan.

Risk Factors Related to the Worldwide Oil and Natural Gas Industry

     For discussion of our risk factors and cautions regarding forward-looking statements, see the “Risk Factors Related to the Worldwide Oil and Natural Gas Industry” in Item 1A. Risk Factors and in the “Forward-Looking Statements” section in Item 6, both contained herein. The risk factors discussed there are not intended to be all inclusive.

BUSINESS OUTLOOK

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

     In our outlook for 2006, we took into account the factors described herein. Revenues in 2006 are expected to increase by approximately 19% to 21%, in line with the expected increase in customer spending. We expect the growth in our revenues will primarily be due to increased activity and pricing improvement. Our assumptions regarding overall growth in customer spending assume strong economic growth in the U.S. and China, resulting in an average oil price exceeding $50/Bbl. Our assumptions regarding customer spending in North America assume strong economic growth in the U.S. and natural gas prices exceeding an average of $8/mmBtu.

     In North America, we expect revenues to increase approximately 21% to 23% in 2006 compared with 2005. We expect spending on land-based projects to continue to increase in 2006 driven by demand for natural gas, following the trend evident in 2005. We also expect offshore spending in the Gulf of Mexico to increase modestly in 2006 compared with 2005. 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 2006.

     In 2005, 2004 and 2003, revenues outside North America were 57.6%, 58.5% and 57.9% of total revenues, respectively. In 2006, we expect revenues outside North America to continue to be between 55% and 60% of total revenues, and we expect these revenues to increase approximately 18% to 21% in 2006 compared with 2005, continuing the multi-year trend of growth in customer spending. Spending on large projects by NOCs is expected to 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 2006. The Middle East, Africa and Latin America regions are expected to grow modestly in 2006 compared with 2005. Our expectations for spending and revenue growth could decrease if there are disruptions in key oil and natural gas production markets, such as Venezuela or Nigeria.

     In 2005, WesternGeco contributed $96.7 million of equity in income of affiliates compared with $34.5 million of equity in income of affiliates in 2004. We expect the trend of improving operating results for WesternGeco to continue throughout 2006. Information regarding WesternGeco’s profitability in 2006 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 net income per diluted share in 2006 will be in the range of $3.40 to $3.60, which includes the impact of expensing stock option awards and stock issued under the employee stock purchase plan of between $18.0 million and $20.0 million, net of tax. Significant price increases, lower than expected raw material and labor costs, higher than planned activity or significantly better than expected results from WesternGeco could cause earnings per share to reach the upper end of this range. Conversely, less than expected price increases, higher than expected raw material and labor costs, lower than expected productivity 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 pricing 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 90 countries including over one-half of the 35 countries having the lowest scores, which indicates high levels of corruption, in Transparency International’s Corruption Perception Index (“CPI”) survey for 2005. We devote significant resources to the development, maintenance and enforcement of our Business Code of Conduct policy, our Foreign Corrupt

Practices Act (the “FCPA”) policy, our internal control processes and procedures and other compliance related policies. Notwithstanding the devotion of such resources, and in part as a consequence thereof, from time to time we discover or receive information alleging potential violations of laws and regulations, including the FCPA and our policies, processes and procedures. We conduct internal investigations of these potential violations and take appropriate action depending upon the outcome of the investigation. In addition, U.S. government agencies and authorities are conducting investigations into allegations of potential violations of laws.

     We anticipate that the devotion of significant resources to compliance related issues, including the necessity for investigations, will continue to be an aspect of doing business in a number of the countries in which oil and natural gas exploration, development and production take place and in which we are requested to conduct operations. Compliance related issues could limit our ability to do business in these countries. In order to provide products and services in some of these countries, we may in the future utilize ventures with third parties, sell products to distributors or otherwise modify our business approach in order to improve our ability to conduct our business in accordance with laws and regulations and our Business Code of Conduct. In the third quarter of 2005, our independent foreign subsidiaries initiated a process to prohibit any business activity that directly or indirectly involves or facilitates transactions in Iran, Sudan or with their governments, including government-controlled companies operating outside of these countries. Implementation of this process should be substantially complete by the end of 2006 and is not expected to have a material impact on our consolidated financial statements.

Risk Factors Related to Our Business

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

CRITICAL ACCOUNTING ESTIMATES

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

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

Allowance for Doubtful Accounts

     The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make frequent judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. Provisions for doubtful accounts are recorded when it becomes evident that the customer will not make the required payments at either contractual due dates or in the future. At December 31, 2005 and 2004, allowance for doubtful accounts totaled $51.4 million, or 3.0%, and $50.2 million, or 3.6%, of total gross accounts receivable, respectively. We believe that our allowance for doubtful accounts is adequate to cover potential bad debt losses under current conditions; however, uncertainties regarding changes in the financial condition of our customers, either adverse or positive, could impact the amount and timing of any additional provisions for doubtful accounts that may be required. A five percent change in the allowance for doubtful accounts would have had a pre–tax impact of approximately $2.6 million in 2005.

Inventory Reserves

     Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions, production requirements and technological developments. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential outcomes. At December 31, 2005 and 2004, inventory reserves totaled $201.3 million, or 15.2%, and $220.0 million, or 17.7%, of gross inventory, respectively. We believe that our reserves are adequate to properly value potential excess, slow moving and obsolete inventory under current conditions. Significant or unanticipated changes to our estimates and forecasts, either adverse or positive, could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had a pre–tax impact of approximately $10.1 million in 2005.

Impairment of Long–Lived Assets

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

Income Taxes

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

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

     Our tax filings for various periods are subjected to audit by the tax authorities in most jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. We believe these assessments may occasionally be based on erroneous and even arbitrary interpretations of local tax law. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. The resulting change to our tax liability, if any, is dependent on numerous factors that are difficult to estimate. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; the sheer number of countries in which we do business; and the potential for changes in the tax paid to one country to

either produce, or fail to produce, an offsetting tax change in other countries. Our experience has been that the estimates and assumptions we have used to provide for future tax assessments have proven to be appropriate. However, past experience is only a guide, and the potential exists, however limited, that the tax resulting from the resolution of current and potential future tax controversies may differ materially from the amount accrued. Although we have provided for the taxes that we believe will ultimately be payable as a result of these assessments, the aggregate assessments are approximately $34.1 million in excess of the taxes provided for in our consolidated financial statements.

     In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we consider it probable that the taxes ultimately payable will exceed those amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies . Future events such as changes in the facts or tax law, judicial decisions regarding existing law or a favorable audit outcome may later indicate the assertion of additional taxes is no longer probable. In that circumstance, it is possible that taxes previously provided would be released.

Pensions and Postretirement Benefit Obligations

     Pensions and postretirement benefit obligations and the related plan expenses are calculated using actuarial models and methods. This involves the use of two critical assumptions, the discount rate and the expected rate of return on assets, both of which are important elements in determining plan expenses and in measuring plan assets and liabilities. We evaluate these critical assumptions at least annually. Although considered less critical, other assumptions used in determining benefit obligations and plan expenses, such as demographic factors like retirement age, mortality and turnover, are also evaluated periodically and are updated to reflect our actual and expected experience.

     The discount rate enables us to state expected future cash flows at a present value on the measurement date. A lower discount rate increases the present value of benefit obligations and increases plan expenses. We used a discount rate of 6.00% in 2005, 6.25% in 2004 and 6.75% in 2003 to determine plan expenses. A 50 basis point reduction in the discount rate would have increased plan expenses in 2005 by $3.4 million.

     To determine the expected rate of return on plan assets, we consider the current and expected asset allocations, as well as historical and expected returns on various categories of plan assets. A lower rate of return increases plan expenses. We assumed rates of return on our plan investments were 8.50% in 2005, 2004 and 2003. A 50 basis point reduction in the expected rate of return on assets of our principal plans would have increased plan expenses in 2005 by $2.9 million.

DISCONTINUED OPERATIONS

     In the fourth quarter of 2005, our management initiated and our Board of Directors approved a plan to sell the Baker Supply Products Division (“SPD”), a product line group within the Completion and Production segment. SPD distributes basic supplies, products and small tools to the drilling industry. In January 2006, we signed a non–binding letter of intent for the sale of SPD. The sale is expected to close in the first quarter of 2006. SPD had revenues of $32.5 million for the year ended December 31, 2005. This transaction is subject to the negotiation and execution of a definitive sale agreement, as well as, various conditions, including satisfactory due diligence review of SPD’s business. There can be no assurance that the transaction will be consummated.

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

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

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

     In 2003, all purchase price adjustments related to the sale of EIMCO Process Equipment (“EIMCO”) were completed, resulting in the release of the escrow balance, of which we received $2.0 million and $2.9 million was returned to the buyer. We recorded an additional loss on the sale of EIMCO 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.

     Cost of revenues for 2004 increased 14.3% compared with 2003. Cost of revenues as a percentage of revenues was 71.6% and 72.8% for 2004 and 2003, respectively. The decrease in cost of revenues as a percentage of revenues is primarily related to limited pricing improvement in certain markets and product lines and improved cost control measures, including lower repair and maintenance costs at our INTEQ division, partially offset by increased material costs and higher employee compensation expense. A change in the geographic and product mix from the sale of our products and services also contributed to the decrease in the cost of revenues as a percentage of revenues. During 2004, our revenue increases came predominantly from outside North America and our margins on revenues generated outside North America are typically higher than margins generated in North America.

Selling, General and Administrative

     Selling, general and administrative (“SG&A”) expenses increased 10.7% in 2005 compared with 2004. The increase corresponds with increased activity and resulted primarily from higher marketing and employee compensation expenses.

     SG&A expenses for 2004 increased 10.6% compared with 2003. This increase was primarily due to higher marketing and administrative expenses as a result of increased activity, including higher employee compensation expense, and increased costs related to our continued focus on compliance, including legal investigations and increased staffing in our legal, compliance and audit groups. The increase was also due to the implementation of programs and procedures as a result of the requirements of the Sarbanes–Oxley Act of 2002.

Reversal of Restructuring Charge

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

Impairment of Investment in Affiliate

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

Equity in Income (Loss) of Affiliates

     Equity in income of affiliates increased $63.8 million in 2005 compared with 2004. The increase is almost entirely due to the increase in equity in income of WesternGeco, our most significant equity method investment. WesternGeco’s revenue and profitability has continued to improve as a result of ongoing favorable market conditions in the seismic industry.

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

Interest Expense and Interest Income

     Interest expense decreased $11.3 million in 2005 compared with 2004. The decrease was primarily due to lower total debt levels partially offset by the impact of the interest rate swap agreement that was in place from April 2004 through June 2005. The lower total debt levels were a result of the repayment of $350.0 million of long–term debt in the second quarter of 2004. Interest income in 2005 increased $11.2 million over 2004, due to significantly higher cash balances and short–term investments during the year resulting primarily from higher cash flows from operations.

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

Income Taxes

     Our effective tax rates differ from the U.S. statutory income tax rate of 35% due to state income taxes, differing rates of tax on international operations and higher taxes within the WesternGeco venture. Additionally, in 2005 we have reflected a $10.6 million reduction to tax expense attributable to the recognition of a deferred tax asset associated with our supplemental retirement plan (“SRP”).

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

     During 2005 and 2003, benefits of $4.3 million and $3.3 million, respectively, were recognized as the result of various refund claims filed in the U.S.

     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 December 31, 2005, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47 (“FIN 47”), Conditional Asset Retirement Obligations . FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The adoption of FIN 47 resulted in a charge of $0.9 million, net of tax of $0.5 million, recorded as the cumulative effect of accounting change in the consolidated statement of operations. In conjunction with the adoption, we recorded conditional asset retirement obligations of $1.6 million as the fair value of the costs associated with the special handling of asbestos related materials in certain facilities. We also have certain facilities that contain asbestos related materials for which a liability has not been recognized because the fair value cannot be reasonably estimated. We believe that there are indeterminate settlement dates for these obligations because the range of time over which we would settle these obligations is unknown or cannot be estimated; therefore, sufficient information does not exist to apply an expected present value technique.

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

     Our capital planning process is focused on utilizing cash flows generated from operations in ways that enhance the value of our company. In 2005, we used cash for a variety of activities including working capital needs, payment of dividends, repurchase of common stock, repayments of borrowings and capital expenditures.

Cash Flows

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

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

Operating Activities

     Cash flows from operating activities have been steadily increasing over the last three years and we expect this trend to continue in 2006. We attribute the increases in our cash flow to the increasing levels of income from continuing operations adjusted for noncash items.

     Cash flows from operating activities of continuing operations increased $167.8 million in 2005 compared with 2004. This increase was primarily due to an increase in income from continuing operations of $349.1 million partially offset by a change in net operating assets and liabilities that used $180.6 million more in cash flows during 2005 compared with 2004.

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

	•		An increase in accounts receivable used $329.4 million in cash in 2005 compared with using $173.7 million in cash in 2004. This was due to the increase in revenues and an increase in days sales outstanding (defined as the average number of days our accounts receivable are outstanding) of approximately three days.
	•		A build up in inventory in anticipation of and related to increased activity used $108.7 million in cash in 2005 compared with using $3.2 million in cash in 2004.
	•		An increase in accounts payable, accrued employee compensation and other accrued liabilities provided $269.6 million in cash in 2005 compared with providing $189.0 million in cash in 2004. This was due primarily to increased activity and increased employee compensation accruals.

     Our contributions to our defined benefit pension plans in 2005 were approximately $48.0 million, a decrease of approximately $62.0 million compared to 2004, due to higher funding in excess of the minimum requirements in 2004.

     Cash flows from operating activities of continuing operations increased $132.8 million in 2004 compared with 2003. The increase was primarily due to increased operating performance attributable to our increased revenues. In addition, changes in net operating assets and liabilities provided $11.1 million less in cash flows during 2004 compared with 2003.

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

	•		An increase in accounts receivable used $173.7 million in cash in 2004 compared with using $13.8 million in cash in 2003. This was due to the increase in revenues and an increase in days sales outstanding of approximately two days.
	•		A build up in inventory in anticipation of increased activity used $3.2 million in cash in 2004 compared with providing $20.7 million in cash in 2003. The build up in inventory was partially offset by our continued focus on improving the utilization of inventory on hand.

•

An increase in accounts payable, accrued employee compensation and other accrued liabilities provided $189.0 million in cash in 2004 compared with providing $16.3 million in cash in 2003. This was due primarily to increased activity and increased employee compensation accruals.

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

Investing Activities

     Our principal recurring investing activity is the funding of capital expenditures to ensure that we have the appropriate levels and types of rental tools in place to generate revenues from operations. Expenditures for capital assets totaled $478.3 million, $348.2 million and $403.9 million for 2005, 2004 and 2003, respectively. The majority of these expenditures were for rental tools and machinery and equipment, including wireline tools and equipment.

     During 2005, we paid $46.8 million for acquisitions of businesses, net of cash acquired. In December, we purchased Zeroth Technology Limited (“Zertech”), a developer of an expandable metal sealing element, for $20.3 million. In November, we paid $25.5 million, net of cash acquired of $1.7 million, for the remaining 50% interest in QuantX Wellbore Instrumentation (“QuantX”), a venture we entered into in 2003 which is engaged in the permanent in–well monitoring market. During 2005, we also made smaller acquisitions having an aggregate purchase price of $1.0 million.

     During 2005, we purchased $77.0 million of auction rate securities, which are highly liquid, variable–rate debt securities. While the underlying security has a long–term maturity, the interest rate is reset through Dutch auctions that are typically held every 7, 28 or 35 days, creating short–term liquidity. These short–term investments are classified as available–for–sale and are recorded at cost, which approximates market value.

     Proceeds from disposal of assets were $90.1 million, $106.9 million and $66.8 million for 2005, 2004 and 2003, respectively. These disposals relate to rental tools that were lost–in–hole, as well as machinery, rental tools and equipment no longer used in operations that were sold throughout the year. Included in the proceeds for 2004 was $12.2 million related to the sale of certain real estate properties held for sale.

     In 2005, we received distributions of $30.0 million from WesternGeco, which were recorded as a reduction in the carrying value of our investment. We also received $13.3 million from Schlumberger related to the WesternGeco true–up payment, of which $13.0 million was recorded as a reduction in the carrying value of our investment and $0.3 million as interest income.

     In May 2005, we received $3.7 million from the release of a portion of the amount held in escrow related to our sale of Petreco International. The remainder is expected to be released to us in the first quarter of 2006, subject to the indemnity obligations under the sales agreement.

     In 2004, we paid $6.6 million for acquisition of businesses, net of cash acquired. We purchased the remaining 60% interest in Luna Energy L.L.C. (“Luna”), a venture we entered into in 2002, for $1.0 million. We also paid $5.6 million in settlement of the final purchase price related to an acquisition completed in a prior year and invested an additional $7.1 million in certain of our investments in affiliates.

     In 2003, we made two acquisitions having an aggregate purchase price of $16.9 million, of which $9.5 million was paid in cash. In addition, during 2003, we invested $38.1 million in affiliates, of which $30.1 million related to our 50% interest in QuantX.

     In 2004, we received $58.7 million in net proceeds from the sale of businesses and our interest in an affiliate. In January, we completed the sale of BIRD and received $5.6 million in proceeds, which were subject to post–closing adjustments to the purchase price. In June 2004, we made a net payment of $6.8 million to the buyer of BIRD in settlement of the final purchase price adjustments. In February 2004, we completed the sale of our minority interest in Petreco International, a venture we entered into in 2001, and received proceeds of $35.8 million, of which $7.4 million was placed in escrow pending the outcome of potential indemnification obligations pursuant to the sales agreement. In September, we also completed the sale of BHMT and received proceeds of $31.5 million.

     In 2003, we received $24.0 million in net proceeds from the sale of businesses. In April, we completed the sale of our interest in an oil producing property in West Africa and received the remaining $22.0 million in proceeds. We also completed all purchase price adjustments related to the sale of our EIMCO division and received $2.0 million from the release of the escrow balance.

     We routinely evaluate potential acquisitions of businesses of third parties that may enhance our current operations or expand our operations into new markets or product lines. We may also from time to time sell business operations that are not considered part of our core business.

Financing Activities

     We had net (repayments) borrowings of commercial paper and other short–term debt of $(71.1) million, $35.5 million and $11.2 million in 2005, 2004 and 2003, respectively. In 2004, we repaid the $100.0 million 8.0% Notes due May 2004 and the $250.0 million 7.875% Notes due June 2004. In 2003, we repaid the $100.0 million 5.8% Notes due February 2003. These repayments were funded with cash on hand, cash flows from operations and the issuance of commercial paper.

     Total debt outstanding at December 31, 2005 was $1,087.9 million, a decrease of $74.4 million compared with December 31, 2004. The total debt to total capitalization (defined as total debt plus stockholders’ equity) ratio was 0.19 at December 31, 2005 and 0.23 at December 31, 2004.

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

     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.

     We received proceeds of $228.1 million, $115.9 million and $61.8 million in 2005, 2004 and 2003, respectively, from the issuance of common stock through the exercise of stock options and the employee stock purchase plan.

     On October 27, 2005, the Board of Directors authorized us to repurchase up to $455.5 million of common stock, which was in addition to the balance of $44.5 million remaining from the Board of Directors’ September 2002 authorization, resulting in the authorization to repurchase up to a total of $500.0 million of common stock. On November 3, 2005, we entered into a Stock Purchase Plan with an agent for the purchase of shares of our common stock that complies with the requirements of Rule 10b5–1 promulgated by the Securities Exchange Act of 1934. The term of the November Plan will run from November 7, 2005 until April 30, 2006, unless earlier terminated. On February 22, 2006, we entered into another Plan for a term that will run from February 23, 2006 until April 30, 2006, unless earlier terminated. During that term, the agent will use its best efforts to repurchase a fixed dollar value of our common stock each trading day, subject to applicable trading rules, until the cumulative amount purchased under the November Plan equals $250.0 million and under the February Plan equals $150.0 million, inclusive of all commissions and fees paid by us to the agent related to such repurchases. Shares will be repurchased by the agent at the prevailing market prices, subject to limitations provided by us, in open market transactions intended to comply with Rule 10b–18 of the Exchange Act. We or the agent may terminate the Plans. However, no shares will be repurchased at any time that the cost of the shares exceeds an amount that has been specified by us to the agent. During the fourth quarter of 2005, we repurchased 1.7 million shares of our common stock at an average price of $58.17 per share, for a total of $98.5 million. During 2003, we repurchased 6.3 million shares at an average price of $28.78 per share, for a total of $181.4 million. Upon repurchase, the shares were retired.

     We paid dividends of $161.1 million, $153.6 million and $154.3 million in 2005, 2004 and 2003, respectively. Beginning in the fourth quarter of 2005 as authorized by our Board of Directors, we increased our quarterly dividend to $0.13 per share, compared to $0.115 per share that was paid in prior quarters.

Available Credit Facilities

     At December 31, 2005, we had $955.6 million of credit facilities with commercial banks, of which $500.0 million is a committed revolving credit facility (the “facility”) that expires in July 2010. The facility provides for up to three one–year extensions, subject to the approval and acceptance by the lenders, among other conditions. In addition, the facility contains a provision to allow for an increase in the facility amount of an additional $500.0 million, subject to the approval and acceptance by the lenders, among other conditions. The facility contains certain covenants which, among other things, require the maintenance of a funded indebtedness to total capitalization ratio (a defined formula per the facility) of less than or equal to 0.60, restrict certain merger transactions or the sale

of all or substantially all of the assets of the company or a significant subsidiary and limit the amount of subsidiary indebtedness. Upon the occurrence of certain events of default, our obligations under the facility may be accelerated. Such events of default include payment defaults to lenders under the facility, covenant defaults and other customary defaults. At December 31, 2005, we were in compliance with all of the facility covenants. There were no direct borrowings under the facility during the year ended December 31, 2005; however, to the extent we have outstanding commercial paper, our ability to borrow under the facility is reduced. At December 31, 2005, we had no outstanding commercial paper.

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

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

Cash Requirements

     In 2006, we believe operating cash flows will provide us with sufficient capital resources and liquidity to manage our working capital needs, meet contractual obligations, fund capital expenditures, pay dividends, repurchase common stock and support the development of our short–term and long–term operating strategies.

     We currently expect 2006 capital expenditures will be between $750.0 million and $780.0 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 2006, we expect to make interest payments of between $72.0 million and $77.0 million. This is based on our current expectations of debt levels during 2006. We also expect to make income tax payments of between $490.0 million and $530.0 million in 2006.

     As of December 31, 2005, we have authorization remaining to repurchase up to $401.5 million in common stock. We may repurchase our common stock depending on market conditions, applicable legal requirements, our liquidity and other considerations. We anticipate paying dividends of between $170.0 million and $180.0 million in 2006; however, the Board of Directors can change the dividend policy at anytime.

     During 2006, we estimate we will contribute between $18.0 million and $23.0 million to our defined benefit pension plans and make benefit payments related to postretirement welfare plans of between $15.0 million and $17.0 million. We also estimate we will contribute between $85.0 million and $95.0 million to our defined contribution plans.

     We do not believe there are any other material trends, demands, commitments, events or uncertainties that would have, or are reasonably likely to have, a material impact on our financial condition and liquidity. Other than 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 2005 are not indicative of what we can expect in the future.

Off–Balance Sheet Arrangements

     In the normal course of business with customers, vendors and others, we have entered into off–balance sheet arrangements, such as letters of credit and other bank issued guarantees, which totaled approximately $319.8 million at December 31, 2005. In addition, at December 31, 2005, we have guaranteed debt and other obligations of third parties with a maximum potential exposure of $1.4 million. None of these off–balance sheet arrangements either has, or is likely to have, a material effect on our current or future financial condition, results of operations, liquidity or capital resources.

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

NEW ACCOUNTING STANDARDS

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

     In December 2004, the FASB issued the revised SFAS No. 123, Share–Based Payment (“SFAS No. 123(R)”). SFAS No. 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS No. 123(R) requires an entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant–date fair value of the award. That cost will be recognized over the period in which an employee is required to provide service in exchange for the award. SFAS No. 123(R) also requires an entity to initially measure the cost of employee services rendered in exchange for an award of liability instruments at its current fair value. The fair value of that award is to be remeasured subsequently at each reporting date through the settlement date. Changes in the fair value during the required service period are to be recognized as compensation cost over that period. In accordance with guidance issued by the SEC that delayed the effective date of SFAS No. 123(R), we adopted SFAS No. 123(R) on January 1, 2006 using the modified prospective method, whereby we will recognize expense on any previously granted unvested awards over the remaining service period of the award. New awards granted after the adoption date will be expensed over the estimated service period. Based on our current estimates, we expect the impact in 2006 of the adoption of SFAS No. 123(R) to be additional expense of between $18.0 million and $20.0 million, net of tax. We are continuing to evaluate the various option pricing models and the required assumptions and estimates that will be used in determining the fair value of awards made in 2006. In addition, we have estimated the number of awards to be granted in 2006 because the final amount has not been determined. As a result, the actual amount recorded as expense in 2006 may be different from this estimated amount and this estimated amount may not be indicative of the expense we may incur in future years.

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

     In December 2004, the FASB issued FASB Staff Position No. 109–2 (“FSP 109–2”), Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109–2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We have decided not to elect to repatriate foreign earnings under the provisions in the Act. Accordingly, our consolidated financial statements do not reflect a provision for taxes related to this election.

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

     In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections . SFAS No. 154 replaces Accounting Principles Board Opinion No. 20 (“APB No. 20”), Accounting Changes , and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements , and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period–specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006.

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 was to be made by either of the parties based on a formula comparing the ratio of the net present value of sales revenue from each party’s contributed multiclient seismic data libraries during the four–year period ending November 30, 2004 and the ratio of the net book value of those libraries as of November 30, 2000. The maximum payment that either party would be required to make as a result of this adjustment was $100.0 million. In August 2005, we received $13.3 million from Schlumberger related to

the true–up payment. We recorded $13.0 million as a reduction in the carrying value of our investment in WesternGeco and $0.3 million as interest income. The income tax effect of $3.3 million related to this payment is included in our provision for income taxes for the year ended December 31, 2005.

     In November 2000, we also entered into an agreement with WesternGeco whereby WesternGeco subleased a facility from us for a period of ten years at then current market rates. During 2005, 2004 and 2003, we received payments of $6.5 million, $5.5 million and $5.0 million, respectively, from WesternGeco related to this lease.

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

     Effective December 1, 2005, either party to the WesternGeco Master Formation Agreement may offer to sell its entire interest in the venture to the other party at a cash purchase price per percentage interest specified in an offer notice. If the offer to sell is not accepted, the offering party will be obligated to purchase and the other party will be obligated to sell its entire interest at the same price per percentage interest as the price specified in the offer notice.

     At December 31, 2005 and 2004, net accounts receivable (payable) from unconsolidated affiliates totaled $0.4 million and $(1.1) million, respectively. There were no other significant related party transactions.

FORWARD–LOOKING STATEMENTS

     MD&A and certain statements in the Notes to Consolidated Financial Statements include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a “forward–looking statement”). The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. Our forward–looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. The statements do not include the potential impact of future transactions, such as an acquisition, disposition, merger, joint venture or other transaction that could occur. We undertake no obligation to publicly update or revise any forward–looking statement. Our expectations regarding our business outlook, including changes in revenue, pricing, capital spending, profitability, strategies for our operations, impact of our common stock repurchases, oil and natural gas market conditions, market share and contract terms, costs and availability of resources, economic and regulatory conditions, and environmental matters are only our forecasts regarding these matters.

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

     At December 31, 2005 and 2004, we had fixed rate debt aggregating $1,075.0 million and $1,075.2 million, respectively. The following table sets forth the required cash payments for our indebtedness, which bear a fixed rate of interest and are denominated in U.S. Dollars, and the related weighted average effective interest rates by expected maturity dates as of December 31, 2005 and 2004 (dollar amounts in millions).

INTEREST RATE SWAP AGREEMENTS

     At December 31, 2005, there were no interest rate swap agreements in effect. Due to our outlook for interest rates, on June 2, 2005, we terminated the interest rate swap agreement we had entered into in April 2004. This agreement had been designated and had qualified as a fair value hedging instrument. Upon termination we were required to pay $5.5 million. This amount is being amortized as an increase to interest expense over the remaining life of the underlying debt security, which matures in January 2009.

     In April 2004, we entered into an interest rate swap agreement for a notional amount of $325.0 million associated with our 6.25% Notes due January 2009. Under the agreement we received interest at a fixed rate of 6.25% and paid interest at a floating rate of six–month LIBOR plus a spread of 2.741%. The interest rate swap agreement was designated and qualified as a fair value hedging instrument. The interest rate swap agreement was fully effective, resulting in no gain or loss recorded in the consolidated statement of operations. We recorded the fair value of the interest rate swap agreement, which was a $2.3 million liability at December 31, 2004, based on quoted market prices for contracts with similar terms and maturity dates.

FOREIGN CURRENCY AND FOREIGN CURRENCY FORWARD CONTRACTS

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

     At December 31, 2005, we had entered into several foreign currency forward contracts with notional amounts aggregating $65.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including the British Pound Sterling, the Norwegian Krone, the Euro and the Brazilian Real. These contracts are designated and qualify as fair value hedging

instruments. Based on quoted market prices as of December 31, 2005 for contracts with similar terms and maturity dates, we recorded a gain of $0.1 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, 2004, we had entered into several foreign currency forward contracts with notional amounts aggregating $78.0 million to hedge exposure to currency fluctuations in various foreign currency payables and receivables, including the British Pound Sterling, the Norwegian Krone, the Euro and the Brazilian Real. These contracts were designated and qualified as fair value hedging instruments. Based on quoted market prices as of December 31, 2004 for contracts with similar terms and maturity dates, we recorded a loss of $0.4 million to adjust these foreign currency forward contracts to their fair market value. This loss offsets designated foreign exchange gains resulting from the underlying exposures and is included in selling, general and administrative expense in the consolidated statement of operations.

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

     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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

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

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

     Based on our evaluation under the framework in Internal Control — Integrated Framework , our principal executive officer and principal financial officer concluded that our internal control over financial reporting was effective as of December 31, 2005. The conclusion of our principal executive officer and principal financial officer is based on the recognition that there are inherent limitations in all systems of internal control. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/s/ CHAD C. DEATON		/s/ G. STEPHEN FINLEY		/s/ ALAN J. KEIFER
Chad C. Deaton		G. Stephen Finley		Alan J. Keifer
Chairman and		Senior Vice President —		Vice President and
Chief Executive Officer		Finance and Administration		Controller
		and Chief Financial Officer

Houston, Texas
February 23, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

     We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Baker Hughes Incorporated and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

     A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

     Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule II as of and for the year ended December 31, 2005 of the Company; and our report dated February 23, 2006, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 23, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

     We have audited the accompanying consolidated balance sheets of Baker Hughes Incorporated and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule II, valuation and qualifying accounts listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

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

     In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Baker Hughes Incorporated and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
February 23, 2006

See Notes to Consolidated Financial Statements

See Notes to Consolidated Financial Statements

See Notes to Consolidated Financial Statements