BJ SERVICES CO - 10-K Annual Report

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 ¨.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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 ¨.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES þ NO ¨.

At December 5, 2003, the registrant had outstanding 158,917,102 shares of Common Stock, $.10 par value per share. The aggregate market value of the Common Stock on March 31, 2003 (based on the closing prices in the daily composite list for transactions on the New York Stock Exchange) held by nonaffiliates of the registrant was approximately $5.4 billion.

Portions of Registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held January 22, 2004 are incorporated by reference into Part II and Part III.

BJ Services Company (the “Company”), whose operations trace back to the Byron Jackson Company (which was founded in 1872), was organized in 1990 under the corporate laws of the state of Delaware. The Company is a leading provider of pressure pumping and other oilfield services serving the petroleum industry worldwide. The Company’s pressure pumping services consist of cementing and stimulation services used in the completion of new oil and natural gas wells and in remedial work on existing wells, both onshore and offshore. Other oilfield services include completion tools, completion fluids and casing and tubular services provided to the oil and natural gas exploration and production industry, commissioning and inspection services provided to refineries, pipelines and offshore platforms, and production chemical services.

In April 1995, the Company completed the acquisition of The Western Company of North America (“Western” and the “Western Acquisition”), which provided the Company with a greater critical mass with which to better compete in domestic and international markets and the realization of significant consolidation benefits. The Western Acquisition increased the Company’s then existing revenue base by approximately 75% and more than doubled the Company’s domestic revenue base at that time.

In June 1996, the Company completed the acquisition of Nowsco Well Service Ltd. (“Nowsco” and the “Nowsco Acquisition”). Nowsco’s operations were conducted primarily in Canada, the United States, Europe, Southeast Asia and Argentina and included pressure pumping and commissioning and inspection services. The Nowsco Acquisition added approximately 40% to the Company’s then existing revenue base.

On May 31, 2002, the Company completed the acquisition of OSCA, Inc. (“OSCA”), a completion services (pressure pumping), completion tools and completion fluids company based in Lafayette, Louisiana, with operations primarily in the U.S. Gulf of Mexico, Brazil and Venezuela.

During the year ended September 30, 2003, the Company generated approximately 83% of its revenue from pressure pumping services and 17% from other oilfield services. Over the same period, the Company generated approximately 50% of its revenue from U.S. operations and 50% from international operations. For geographic revenue, segment revenue, operating income, identifiable asset, and long-lived asset details for each of the three years ended September 30, 2003, see Note 8 of the Notes to Consolidated Financial Statements.

The Company’s cementing services, which accounted for approximately 28% of total revenue during 2003, consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped into a well between the casing and the wellbore. The additives and the properties of the slurry are designed to achieve the proper cement set up time, compressive strength and fluid loss control, and vary depending upon the well depth, downhole temperatures and pressures, and formation characteristics. For revenue by product line for each of the three years ended September 30, 2003, see Note 8 of the Notes to Consolidated Financial Statements.

The Company provides central, regional and district laboratory testing services to evaluate slurry properties, which vary with cement supplier and local water sources. Job design recommendations are developed by the Company’s field engineers to achieve desired compressive strength and bonding characteristics.

The principal application for cementing services used in oilfield operations is the cementing between the casing pipe and the wellbore during the drilling and completion phase of a well (“primary cementing”). Primary cementing is performed to (i) isolate fluids behind the casing between productive formations and other formations that would damage the productivity of hydrocarbon producing zones or damage the quality of

freshwater aquifers, (ii) seal the casing from corrosive formation fluids and (iii) provide structural support for the casing string. Cementing services are also utilized when recompleting wells from one producing zone to another and when plugging and abandoning wells.

The Company’s stimulation services, which accounted for approximately 53% of total revenue during 2003, consist of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tools. The Company participates in the offshore stimulation market through the use of skid-mounted pumping units and operation of several stimulation vessels including one in the North Sea, three in the Gulf of Mexico and four in South America.

The Company believes that as production continues to decline in key producing fields of the U.S. and certain international regions, the demand for fracturing and other stimulation services is likely to increase. Consequently, the Company has been increasing its pressure pumping capabilities in certain international markets over the past several years. For revenue by product line for each of the three years ended September 30, 2003, see Note 8 of the Notes to Consolidated Financial Statements. These services are designed to improve the flow of oil and natural gas from producing formations and are summarized as follows:

Fracturing. Fracturing services are performed to enhance the production of oil and natural gas from formations having such permeability that the natural flow is restricted. The fracturing process consists of pumping a fluid gel into a cased well at sufficient pressure to “fracture” the formation. Sand, bauxite or synthetic proppants are suspended in the gel and are pumped into the fracture to prop it open. The size of a fracturing job is generally expressed in terms of pounds of proppant, which can exceed 200,000 lbs. In some cases, fracturing is performed by an acid solution pumped under pressure without a proppant or with small amounts of proppant. The main pieces of equipment used in the fracturing process are a blender, which blends the proppant and chemicals into the fracturing fluid, multiple pumping units capable of pumping significant volumes at high pressures, and a monitoring van loaded with real time monitoring equipment and computers used to control the fracturing process. The Company’s fracturing units are capable of pumping slurries at pressures of up to 20,000 pounds per square inch. In 1998, the Company embarked on a program to replace its aging U.S. fracturing pumps fleet with new, more efficient and higher horsepower pressure pumping equipment. The Company has made significant progress with this program, which is now approximately 65% complete.

An important element of fracturing services is the design of the fracturing treatment, which includes determining the proper fracturing fluid, proppants and injection program to maximize results. The Company’s field engineering staff provide technical evaluation and job design recommendations as an integral element of its fracturing service for the customer. Technological developments in the industry over the past several years have focused on proppant concentration control (i.e., proppant density), liquid gel concentrate capabilities, computer design and monitoring of jobs and cleanup properties for fracturing fluids. The Company has introduced equipment and products to respond to these technological advances.

Acidizing. Acidizing enhances the flow rate of oil and natural gas from wells with reduced flow caused by formation damage from drilling or completion fluids, or the buildup over time of materials that block the formation. Acidizing entails pumping large volumes of specially formulated acids into reservoirs to dissolve barriers and enlarge crevices in the formation, thereby eliminating obstacles to the flow of oil and natural gas. The Company maintains a fleet of mobile acid transport and pumping units to provide acidizing services for the onshore market, and maintains acid storage and pumping equipment on most of its offshore stimulation vessels.

Sand Control. Sand control services involve pumping gravel to fill the cavity created around a wellbore during drilling. The gravel provides a filter for the exclusion of formation sand from the producing wellbore. Oil and natural gas are then free to move through the gravel into the wellbore. These services are utilized primarily in unconsolidated sandstone reservoirs, mostly in the Gulf of Mexico, the North Sea, Venezuela, Brazil, Trinidad, West Africa, Indonesia and India. Completion tools, as described elsewhere herein, are often utilized in conjunction with sand control services.

Nitrogen. There are a number of uses for nitrogen, an inert gas, in pressure pumping operations. Used alone, it is effective in displacing fluids in various oilfield applications, including underbalanced drilling. However, nitrogen services are used principally in applications supporting the Company’s coiled tubing and stimulation services.

Coiled Tubing. Coiled tubing services involve injecting coiled tubing into wells to perform various well-servicing operations. The application of coiled tubing has increased in recent years due to improvements in coiled tubing technology. Coiled tubing is a flexible steel pipe with a diameter of less than five inches manufactured in continuous lengths of thousands of feet and wound or coiled along a large reel on a truck or skid-mounted unit. Due to the small diameter of coiled tubing, it can be inserted through existing production tubing and used to perform workovers without using a larger, more costly workover rig. The other principal advantages of employing coiled tubing in a workover include (i) not having to “shut-in” the well during such operations, thereby allowing production to continue and reducing the risk of formation damage to the well, (ii) the ability to reel continuous coiled tubing in and out of a well significantly faster than conventional pipe, which must be jointed and unjointed, (iii) the ability to direct fluids into a wellbore with more precision, allowing for localized stimulation treatments and providing a source of energy to power a downhole motor or manipulate downhole tools and (iv) enhanced access to remote or offshore fields due to the smaller size and mobility of a coiled tubing unit. The Company has developed a line of specialty downhole tools that may be run on coiled tubing, including rotary jetting equipment and through-tubing inflatable packer systems.

Service Tools. The Company provides service tools and technical personnel for well servicing applications in select markets throughout the world. Service tools, which are used to perform a wide range of downhole operations to maintain or improve a well, generally are rented by customers from the Company. While marketed separately, service tools are usually provided during the course of providing other pressure pumping services.

The Company’s other oilfield services accounted for approximately 17% of the Company’s total revenue in 2003. The other oilfield services segment consists of casing and tubular services, process and pipeline services, production chemicals, and, with the acquisition of OSCA on May 31, 2002, completion tools and completion fluids services in the U.S. and select markets internationally. Revenue for this segment for each of the three years ended September 30, 2003, is presented in Note 8 of the Notes to Consolidated Financial Statements.

Casing and Tubular Services. Casing and tubular services comprise installing (or “running”) casing and production tubing into a wellbore. Casing is run to protect the structural integrity of the wellbore and to seal various zones in the well. These services are primarily provided during the drilling and completion phases of a well. Production tubing is run inside the casing. Oil and natural gas are produced through the tubing. These services are provided during the completion and workover phases.

Process and Pipeline Services. Process services involve inspecting and testing the integrity of pipe connections in offshore drilling and production platforms and onshore and offshore pipelines and industrial plants. These services are provided during the commissioning, decommissioning, installation or construction stages of these infrastructures, as well as during routine maintenance checks. Historically, hydrocarbon storage and production facilities have been tested for leaks using either water under pressure or a “live” system whereby oil, gas or water was introduced at operating pressure. At remote locations such as offshore facilities, the volume of fresh water required to test a facility made its use impractical and the use of flammable or toxic fluids created a risk of explosion or other health hazards. Commission leak testing, or CLT, uses a nitrogen and helium gas mixture in conjunction with certain specialized equipment to detect very small leaks in joints, instruments and valves that form the components of such facilities. Although the process is safer and more practical than traditional leak detection methods, it may be more expensive. Accordingly its use is restricted to those instances where environmental and safety concerns are particularly acute.

Pipeline testing and commissioning services include filling the pipeline with water, pressure testing, de-watering, and then either vacuum, dry air or nitrogen drying of pipelines. Recent technical innovations include the development of pipeline gels, both hydrocarbon and aqueous, for pipeline cleaning and transport of debris that has settled out in the pipelines. The Company has also developed high friction pig trains used in cleaning pipelines and has freezing techniques for the isolation of sections of pipelines.

In conducting its pipeline inspection business, the Company uses “intelligent pigs.” Intelligent pigs are pipeline monitoring vehicles which, together with interpretational software, offer to pipeline operators, constructors and regulators measurement of pipeline wall thickness (detects corrosion), geometry (detects the movement, dents, and ovality of the pipeline), determination of pipeline location (latitude, longitude, and height or plan and profile). Using the acquired data, the customer can develop a structural analysis to ascertain if the pipeline is fit for purpose. The operator’s planning is improved through the utilization of the data to determine the pipeline’s status, estimate current and future reliability and determine appropriate remedial or maintenance requirements. Some pipeline operators routinely use intelligent pigs as part of their maintenance monitoring programs as a method for increasing safety for people, property and the environment.

Production Chemical Services. Production chemical services are provided to customers in the upstream and downstream oil and natural gas businesses through the BJ Chemical Services (formerly BJ Unichem). These services involve the design of treatments and the sale of products to reduce the negative effects of corrosion, scale, paraffin, bacteria, and other contaminants in the production and processing of oil and natural gas. BJ Chemical Services products are used by customers engaged in crude oil production, natural gas processing, raw and finished oil and natural gas product transportation, operating refineries and petrochemical manufacturing. BJ Chemical Services operations address two principal priorities: (1) the protection of the customer’s capital investment in metal goods, such as downhole casing and tubing, pipelines and process vessels, and (2) the treatment of fluids to allow them to meet the specifications of the particular operation, such as production transferred to a pipeline, water discharged overboard from a platform, or fuel sold at a marketing terminal.

Completion Tools. The Company designs, builds and installs downhole completion tools that deploy gravel to control the migration of reservoir sand into the well and direct the flow of oil and natural gas into the production tubing. The Company has a specialty tool manufacturing plant in Mansfield, Texas which manufactures some of the components required in the completion tools. In addition, spare parts for completion tools and production packers are sold to customers that have purchased tools in the past.

The Company’s completion tools are sold as complete systems, which are customized based on each well’s particular mechanical and reservoir characteristics, such as downhole pressure, wellbore size and formation type. Many wells produce from more than one productive zone simultaneously. Depending on the customer’s preference, the Company has the ability to install tools that can either isolate one producing zone from another or integrate the production from multiple zones. Once the tool systems are designed and customized, each is inspected for quality assurance before it is delivered to the well location. The Company’s field specialists, working with the rig crews, deploy completion tools in the well during the completion process.

To further enhance reservoir optimization, the Company has also developed the tools necessary to provide the operator with “intelligent completion” capabilities. The Company’s tools selectively control flow from multiple productive zones in the same wellbore from a remote activation site on surface. The Company from time to time may also outsource the equipment necessary to monitor downhole parameters such as temperature, pressure and reservoir flow to allow optimization of well productivity.

In addition to tools that are designed to control sand migration, the Company also provides completion tools that are generally used in conventional completions for reservoirs that do not require sand control. These tools include non-proprietary production packers and other tools that are delivered through distribution networks located in key domestic markets and select international markets.

Completion Fluids. The Company sells and reclaims clear completion fluids and performs related fluid maintenance activities, such as filtration and reclamation. Completion fluids are used to control well pressure and facilitate other completion activities, while minimizing reservoir damage. The Company provides commodity completion fluids as well as a broad line of specially formulated and customized fluids for critical completion applications.

Completion fluids are available either as pure salt solutions or in combination with other materials for increased flexibility and greater cost-effectiveness. These fluids are solids-free, and therefore will not physically plug oil and natural gas reservoirs. In contrast, drilling mud, the fluid typically used during drilling and for some well completions contains solids to achieve densities greater than water. These solids plug the reservoir, causing reservoir damage and restricting the flow of oil and natural gas into the well. When completion fluids are placed into a well, they typically become contaminated with solids that are left in the well after drilling mud is displaced. To remove these contaminants, the Company deploys filtering equipment and technicians that work in conjunction with the Company’s on-site fluid engineers to maintain the solids-free condition of the completion fluids throughout the project. The Company provides an entire range of completion fluids, as well as all support services needed to properly apply completion fluids in the field, including filtration, on-site engineering, additives and rental equipment.

Pressure pumping services are provided both on land and offshore on a 24-hour, on-call basis through regional and district facilities in approximately 200 locations worldwide. Services are provided utilizing complex truck or skid-mounted equipment designed and constructed for the particular pressure pumping service furnished. After equipment is transported to a well location it is configured with appropriate connections to perform the services required. The mobility of this equipment permits the Company to provide pressure pumping services to wellsites in virtually all geographic areas. Most units are equipped with computerized systems that allow for real-time monitoring and control of the cementing processes. Management believes that the Company’s pressure pumping equipment is adequate to service both current and projected levels of market activity in the near term.

Principal materials utilized in pressure pumping include cement, fracturing proppants, acid, guar polymers, nitrogen, carbon dioxide and other bulk chemical additives. Generally these items are available from several suppliers, and the Company uses more than one supplier for each item. The Company also produces certain of its specialized pressure pumping products through company-owned blending facilities in Germany, Singapore, Canada, the U.S. and Brazil. Sufficient material inventories are generally maintained to allow the Company to provide on-call services to its customers to whom the materials are sold in the course of providing pressure pumping services. Repair parts and maintenance items for pressure pumping equipment are carried in inventory at levels that the Company believes will allow continued operations without significant downtime caused by parts shortages. The Company has experienced only intermittent tightness in supply or extended lead times in obtaining necessary supplies of these materials or repair parts and does not anticipate any chronic shortage of any of these items in the foreseeable future.

The Company believes that coiled tubing and other materials utilized in performing coiled tubing services are and will continue to be widely available from a number of manufacturers. Although there are only three principal manufacturers of the reels around which the coiled tubing is wrapped, the Company has not experienced any difficulty in obtaining coiled tubing reels in the past and anticipates no such difficulty in the future.

The Company maintains three primary engineering and support service centers—one in Tomball, Texas, one in Houston, Texas and the other in Calgary, Alberta. The Company’s research and development organization is divided into six distinct areas: Product Development, Software Applications, Instrumentation Engineering, Mechanical Engineering, Coiled Tubing Engineering and Completion Tools Engineering.

Product Development. The product development laboratory specializes in developing products with enhanced performance characteristics in the fracturing, acidizing, sand control and cementing operations (i.e., “frac fluids” and “cement slurries”). As fluids must perform under a wide range of downhole pressures, temperatures and other conditions, this process is a critical element in developing products to meet customer needs.

Software Applications. The Company’s software applications group develops and supports a wide range of proprietary software utilized in the monitoring of both cement and stimulation job parameters. This software, combined with the Company’s internally developed monitoring hardware, allows for real-time job control as well as post-job analysis.

Instrumentation Engineering. The pressure pumping industry utilizes an array of monitoring and control instrumentation as an integral element of providing cementing and stimulation services. The Company’s monitoring and control instrumentation, developed by its instrumentation engineering group, complements its products and equipment and provides customers with desired real-time monitoring of critical applications.

Mechanical Engineering. Though similarities exist between the major pressure pumping competitors in the general design of their pumping equipment, the actual engine/transmission configurations as well as the mixing and blending systems differ significantly. Additionally, different approaches to the integrated control systems result in equipment designs which are usually distinct in performance characteristics for each competitor. The Company’s mechanical engineering group is responsible for the design of virtually all of the Company’s primary pumping and blending equipment. The Company’s mechanical engineering group provides new product design as well as support to the rebuilding and field maintenance functions.

Coiled Tubing Engineering. The coiled tubing engineering group is located in Calgary, Alberta. This group provides most of the support and research and development activities for the Company’s coiled tubing services, including coiled tubing directional drilling technology. The Company is also actively involved in the ongoing development of downhole tools that may be run on coiled tubing.

Completion Tools Engineering. The completions tools research facility in Houston, Texas specializes in the designing, manufacturing and testing of completion tools. Since the Company’s tools are often installed miles below the earth’s surface, it is critical that potential design flaws be diagnosed and prevented prior to installation. Optimal tool configuration is determined by considering a variety of factors, including different raw materials, operating conditions and design specifications.

In addition to the engineering facility, the Company’s research and technology center in Tomball, Texas also houses its main equipment and instrumentation manufacturing facility. This operation currently includes equipment design, manufacturing and testing, warehousing, distribution, laboratory, training and engineering capabilities along with numerous support operations. The Company produces certain components and spare parts required for the assembly of downhole completion tools and service tools at a manufacturing facility in Mansfield, Texas. The Company also has smaller manufacturing capabilities in several international locations. The Company employs outside vendors for manufacturing various units, engine and transmission rebuilding, and certain fabrication work, but is not dependent on any one source.

Pressure Pumping Services. There are two primary companies with which the Company competes in pressure pumping services, Halliburton Energy Services, a division of Halliburton Company, and Schlumberger Ltd. These companies have operations in most areas of the U.S. in which the Company participates and in most international regions. It is estimated that these two competitors, along with the Company, provide approximately 90% of pressure pumping services to the industry. Several smaller companies compete with the Company in

certain areas of the U.S. and in certain international locations. The principal methods of competition which apply to the Company’s business are its prices, service record and reputation in the industry. While Halliburton Energy Services and Schlumberger are larger in terms of overall pressure pumping revenue, the Company has the largest market share position in certain geographic areas.

Other Oilfield Services. The Company believes that it is one of the largest suppliers of casing and tubular services in the U.K. North Sea and has expanded such services into other international markets in the past several years. The largest provider of casing and tubular services is Weatherford International, Inc. In the U.K., casing and tubular services are typically provided under long-term contracts which limit the opportunities to compete for business until the end of the contract term. In continental Europe, shorter-term contracts are typically available for bid by the provider of casing and tubular services. The Company believes it is the largest provider of commissioning and leak detection services and one of the largest providers of pipeline inspection services. Pipeline Integrity International Ltd. (a division of General Electric) and H. Rosen Engineering GmbH are our principal competitors in pipeline inspection. In production chemical services, there are several competitors significantly larger than the BJ Chemical Services. The Company’s principal competitors in completion fluids are Baroid Corporation, a subsidiary of Halliburton Company; M-I LLC, a joint venture of Smith International, Inc. and Schlumberger Limited; and Tetra Technologies, Inc. The Company’s principal competitors in completion tools are Halliburton Energy Services, a division of Halliburton Company; Schlumberger Limited, Baker Hughes Incorporated and Weatherford International, Inc.

Demand for the Company’s services and products depends primarily upon the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity worldwide. With the exception of Canada and to a lesser degree Process and Pipeline Services, the Company is not significantly impacted by seasonality.

The Company’s principal customers consist of major and independent oil and natural gas producing companies. During 2003, the Company provided services to several thousand customers, none of which accounted for more than 5% of consolidated revenue. While the loss of certain of the Company’s largest customers could have a material adverse effect on Company revenue and operating results in the near term, management believes the Company would be able to obtain other customers for its services in the event of a loss of any of its largest customers.

United States. The United States represents the largest single pressure pumping market in the world. The Company provides its pressure pumping services to its U.S. customers through a network of more than 50 locations throughout the U.S., a majority of which offer both cementing and stimulation services. Demand for the Company’s pressure pumping services in the U.S. is primarily driven by oil and natural gas drilling activity, which tends to be extremely volatile depending on the current and anticipated prices of oil and natural gas. Due to aging oilfields and lower-cost sources of oil internationally, drilling activity in the U.S. has declined more than 75% from its peak in 1981. Record low drilling activity levels were experienced in 1986 and 1992 and again in 1999. Despite a recovery in the latter half of fiscal 1999, the U.S. average fiscal 1999 rig count of 601 active rigs represented the lowest in recorded history. The recovery in U.S. drilling, however, continued throughout fiscal 2000 and 2001 due to exceptionally strong oil and natural gas prices, yet drilling activity retreated in fiscal 2002. For the 12 months ended September 30, 2003, the active U.S. rig count averaged 966 rigs, a 11% increase from fiscal 2002. Much of the increase occurred in the number of rigs drilling for natural gas, which increased 12% from the previous fiscal year. Crude oil and natural gas prices have stabilized over the past several months and U.S. drilling activity has leveled out. The Company’s management believes that average rig count for fiscal 2004 will be approximately 14% higher than fiscal 2003, essentially flat with current levels of approximately 1,100 rigs. During fiscal 2002, the Company expanded its deepwater offshore stimulation capabilities in the Gulf of Mexico through the acquisition of OSCA, which added two stimulation vessels, and the commissioning of the “Blue Ray” stimulation vessel in November 2001.

International. The Company operates in more than 50 countries in the major international oil and natural gas producing areas of Latin America, Europe, Africa, Russia, Asia, Canada and the Middle East. The Company generally provides services to its international customers through wholly-owned foreign subsidiaries. Additionally, the Company holds certain controlling and minority interests in several joint venture companies, through which it conducts a portion of its international operations. The Company’s Canadian operations now represent its largest international operation with approximately 12% of the Company’s consolidated revenue in fiscal 2003.

Drilling activity outside North America has historically been less volatile than the U.S. markets. Due to the significant investment and complexity in international projects, management believes drilling decisions relating to such projects tend to be evaluated and monitored with a longer-term perspective with regard to oil and natural gas pricing. Additionally, the international market is dominated by major oil companies and national oil companies which tend to have different objectives and more operating stability than the typical independent producer in North America. International activities have been increasingly important to the Company’s results of operations since 1992, when the Company implemented a strategy to expand its international presence. During fiscal 2001, the Company completed expansion projects in Saudi Arabia, Kazakhstan and West Africa. In fiscal 2002, the Company expanded in Russia through the purchase of additional workover rigs and enhanced its market position in the Brazilian offshore market with the addition of the “Blue Shark” stimulation vessel. In addition, the Company expanded its service offering in Brazil through the acquisition of OSCA, and by acquiring the assets and business of a leading provider of coiled tubing services in Brazil. During fiscal 2003, the Company established a new operating base in El Salvador to provide pumping services to clients operating in the area. In addition, during fiscal 2003 the Company’s pumping service activities were expanded to New Zealand, Mozambique and Turkey to provide services for drilling, workover and stimulation projects.

The Company now operates in most of the major oil and natural gas producing regions of the world. International operations are subject to risks that can materially affect the sales and profits of the Company, including currency exchange rate fluctuations, the impact of inflation, governmental expropriation, exchange controls, political instability and other risks. The Company mitigates the risk of currency exchange rate fluctuations by invoicing the majority of its international services in U.S. dollars.

At September 30, 2003, the Company had a total of 11,990 employees. Approximately 63% of the Company’s employees were employed outside the United States. At September 30, 2003, the Company had a sufficient number of trained employees to meet customer requirements. However, in times of rapidly expanding activity temporary labor shortages may occur.

The Company’s business is affected both directly and indirectly by governmental regulations relating to the oil and natural gas industry in general, as well as environmental and safety regulations which have specific application to the Company’s business.

The Company, through the routine course of providing its services, handles and stores bulk quantities of hazardous materials. In addition, leak detection services involve the inspection and testing of facilities for leaks of hazardous or volatile substances. If leaks or spills of hazardous materials handled, transported or stored by the Company occur, the Company may be responsible under applicable environmental laws for costs of remediating damage to the surface, sub-surface or aquifers incurred in connection with such occurrence. Accordingly, the Company has implemented and continues to implement various procedures for the handling and disposal of hazardous materials. Such procedures are designed to minimize the occurrence of spills or leaks of these materials.

The Company has implemented and continues to implement various procedures to further assure its compliance with environmental regulations. Such procedures generally pertain to the operation of underground storage tanks, disposal of empty chemical drums, improvement to acid and wastewater handling facilities and cleaning of certain areas at the Company’s facilities. The estimated future cost for such procedures is

$3.3 million, which will be incurred over a period of several years, and for which the Company has provided appropriate reserves. In addition, the Company maintains insurance for certain environmental liabilities which the Company believes is reasonable based on its knowledge of the industry.

The Comprehensive Environmental Response, Compensation and Liability Act, also known as “Superfund,” imposes liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. Certain third-party owned disposal facilities used by the Company or its predecessors have been investigated under state and federal Superfund statutes, and the Company is currently named as a potentially responsible party for cleanup at three such sites. Although the Company’s level of involvement varies at each site, in general, the Company is one of numerous parties named and will be obligated to pay an allocated share of the cleanup costs. While it is not feasible to predict the outcome of these matters with certainty, management is of the opinion that their ultimate resolution should not have a material adverse effect on the Company’s operations or financial position.

Research and development activities for pressure pumping services are directed primarily toward improvement of existing products and services and the design of new products and processes to meet specific customer needs. The Company currently holds numerous patents of varying remaining durations relating to products and equipment used in its pumping services business. While such patents, in the aggregate, are important to maintaining the Company’s competitive position, no single patent is considered to be of a critical or essential nature.

To remain competitive in pumping services, the Company devotes significant resources to developing technological improvements to its pumping services products. Many of these improvements have centered on improving products in fracturing systems and, more recently, in deepwater cementing applications.

In 1991, the Company introduced a borate-based fracturing fluid, Spectra Frac G^®, which is being widely used in the U.S. stimulation market and the North Sea. In 1993, this product was complemented with two additional fracturing fluids, Spartan Frac^® and Medallion Frac^®, which have expanded the Company’s services line offering to cover a broader range of economic and downhole design variables. During 1994, the Company commercialized a proprietary enzyme process used in conjunction with these three fracturing fluids. These “enzyme breakers” significantly enhance the production of oil and natural gas in a wide range of wells. During 1998, the Company introduced a low polymer fracturing fluid (Vistar^®) designed to provide greater fracture length with minimal polymer residue. This product has been successfully utilized in a wide variety of applications since 1998. During 1999 and 2000, the Company successfully field tested in the U.S. a low and mid stress range deformable particle (FlexSand^™) designed to prevent proppant flowback and extend the life of the fracturing treatment. During 2001 and 2002, the Company commercialized the FlexSand additive globally and successfully field tested a high stress range version of the deformable particle.

To address the trend towards more deepwater completions, the Company has developed DeepSet^™, a cementing system designed to handle low sea floor temperatures, and further commercialized automated foam cementing equipment designed to address shallow water flows typically found in deepwater environments.

During 2000 and 2001, the Company successfully field tested and commercialized the TST-3^™ service tool packer. This packer provides the latest in service tool technology and operational efficiency. During 2001 and 2002, the Company successfully field tested and commercialized a composite drillable bridge plug, the Python^™, for which patents have been granted and are pending. The Python plug performs at temperatures in excess of 375°F and differential pressures greater than 10,000 pounds per square inch.

The testing and development of new products is an integral part of the Company’s pipeline inspection and coiled tubing businesses. Developments include a magnetic flux leakage (MFL) corrosion inspection tool; ROTO-JET^®, a tool for use in wellbore scale removal; the SandVac^®/Well Vac^™ treatment tool (a tool

incorporating a hydraulic jet pump to effectively remove sand and other particles hindering production from the wellbore); the Tornado^™ treatment tool and well cleaning system (a patented tool and method employing switchable forward and rearward facing jets that can be used to remove sand from deviated wellbores at much higher efficiencies than previously obtainable); and various downhole tools and other technologies used in directional drilling applications using coiled tubing. During 2001 and 2002, the Company globally commercialized the LEGS^™ (lateral entry guidance system) tool for use with coiled tubing re-entry into vertical and horizontal wells containing lateral wellbores. The LEGS^™ tool provides the technology to locate and successfully enter laterals for workover operations in existing wells. Additionally, the Company operates under various license arrangements, generally ranging from 10 to 20 years in duration, relating to certain products or techniques. None of these license arrangements is material to the Company’s operations overall.

During 2002, the Company actively marketed Liquid Stone^®, a patented storable cement slurry, as a primary cementing method in both land and offshore operations. Liquid Stone technology produces a high quality, fit-for-purpose cement slurry that can be stored in a liquid state for a period of days or weeks prior to placement in the well. During 2002, the Company also actively marketed AquaCon^™ Relative Permeability Modifier (“RPM”) technology for water control and production enhancement applications. AquaCon^™ is a patented RPM system that is effective in both sandstone and carbonate formations.

During 2003, the Company introduced LiteProp^™ lightweight proppants. LiteProp^™ lightweight proppants are stand-alone sand substitutes having lower specific gravities than sand. The patent pending LiteProp proppants and systems provide an improved ability to place proppant deeper into the producing zones of the formation and achieve longer effective fracture lengths.

The Company intends to continue to devote significant resources to its research and development efforts. For information regarding the amounts of research and development expenses for each of the three fiscal years ended September 30, 2003, see Note 12 of the Notes to Consolidated Financial Statements.

This document and our other filings with the Securities and Exchange Commission and our other materials released to the public contain “forward-looking statements,” as defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements discuss the Company’s prospects, expected revenue, expenses and profits, strategies for its operations and other subjects, including conditions in the oilfield service and oil and gas industries and in the United States and international economy in general.

Our forward-looking statements are based on assumptions that we believe to be reasonable but that may not prove to be accurate. All of the Company’s forward-looking information is, therefore, 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 discussed below.

Business Risks. The Company’s results of operations could be adversely affected if its business assumptions do not prove to be accurate or if adverse changes occur in the Company’s business environment, including the following areas:

Risks of Economic Downturn. In the event of an economic downturn in the United States or globally, there may be decreased demand and lower prices for oil and natural gas and therefore for our products and services. The Company’s customers are generally involved in the energy industry, and if these customers experience a business decline, we may be subject to increased exposure to credit risk. If an economic downturn occurs, our results of operations may be adversely affected.

Risks from Operating Hazards. The Company’s operations are subject to hazards present in the oil and natural gas industry, such as fire, explosion, blowouts and oil spills. These incidents as well as accidents or problems in normal operations can cause personal injury or death and damage to property or the environment. The customer’s operations can also be interrupted. From time to time, customers seek to recover from the Company for damage to their equipment or property that occurred while the Company was performing work. Damage to the customer’s property could be extensive if a major problem occurred. For example, operating hazards could arise:

Risks from Unexpected Litigation. The Company has insurance coverage against operating hazards that it believes is customary in the industry. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The Company’s insurance premiums can be increased or decreased based on the claims made by the Company under its insurance policies. The insurance does not cover damages from breach of contract by the Company or based on alleged fraud or deceptive trade practices. Whenever possible, the Company obtains agreements from customers that limit the Company’s liability. Insurance and customer agreements do not provide complete protection against losses and risks, and the Company’s results of operations could be adversely affected by unexpected claims not covered by insurance.

Risks from International Operations. The Company’s international operations are subject to special risks that can materially affect the Company’s sales and profits. These risks include:

Weather. The Company’s performance is significantly impacted by the demand for natural gas in North America. Warmer than normal winters in North America, among other factors, may adversely impact demand for natural gas and therefore, demand for the Company’s services. Conversely, colder than normal winters may positively impact demand for natural gas and the Company’s services.

Other Risks. Other risk factors that could cause actual results to be different from the results we expect include:

Many of these risks are beyond the control of the Company. In addition, future trends for pricing, margins, revenue and profitability remain difficult to predict in the industries we serve and under current economic and political conditions. Except as required by applicable law, we do not assume any responsibility to update any of our forward-looking statements.

The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section13 (a) or 15 (d) of the Exchange Act are made available free of charge on the Company’s internet website at http://www.bjservices.com on the same day that we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

The current executive officers of the Company and their positions and ages are as follows:

Mr. Stewart joined Hughes Tool Company in 1969 as Project Engineer. He served as Vice President—Legal and Secretary of Hughes Tool Company and as Vice President—Operations for a predecessor of the Company prior to being named President of the Company in 1986. In 1990, he was also named Chairman and Chief Executive Officer of the Company.

Mr. Airola joined the Company as Assistant General Counsel in 1995 from Cooper Industries, Inc., a diversified manufacturing company, where he served as Senior Litigation Counsel. He was named Chief Compliance Officer in 2003.

Ms. Douget joined the Company in October 1979 and was promoted to Director, Human Resources in June 2003. Prior to being promoted Director, she held various positions within the Human Resources function.

Mr. Dunlap joined the Company in 1984 as a District Engineer and was named Vice President—International Operations in December 1995. He has previously served as Vice President—Sales for the Coastal Division of North America and U.S. Sales and Marketing Manager.

Mr. Hoel joined the Company in 1992 as an Account Manager and was named Region Sales Manager in 1993. He previously served as Vice President of Sales for the U.S. Western Division, prior to being named Vice President—Technology and Logistics in 2002.

Mr. McCole originally joined the Company as Director of Internal Audit in 1991. He also served as Controller of the Asia Pacific Region and Controller of BJ Chemical Services (formerly BJ Unichem). He left the Company in 1998 and returned in 2001 to serve as Director of Internal Audit until becoming Controller in 2002.

Ms. Shannon joined the Company in 1994 as Vice President—General Counsel from the law firm of Andrews Kurth LLP, where she had been a partner since 1984.

Mr. Smith joined the Company in 1990 as Financial Reporting Manager. He also served as Director, Financial Planning. In 1997 he was promoted to Director, Business Development, a position he held until being named Treasurer in 2002. Prior to joining BJ Services, he held various positions with Baker Hughes Incorporated.

Mr. Whichard joined the Company as Tax and Treasury Manager in 1989 from Weatherford International and was named Treasurer in 1992 and Vice President in 1998. Prior to being named Vice President, Finance and Chief Financial Officer in 2002, he served in various positions including Treasurer, Tax Director and Assistant Treasurer.

Mr. Williams joined the Company in 1973 and has since held various positions in the U.S. operations. Prior to being named Vice President—North American Operations in 1991, he served as Region Manager—Western U.S. and Canada.

The Company’s properties consist primarily of pressure pumping and blending units and related support equipment such as bulk storage and transport units. Although a portion of the Company’s U.S. pressure pumping and blending fleet is being utilized through a servicing agreement with an outside party (see Lease and Other Long-Term Commitments in Note 10 of the Notes to the Consolidated Financial Statements), the majority of its worldwide fleet is owned and unencumbered. The Company’s tractor fleet, most of which is owned, is used to transport the pumping and blending units. The majority of the Company’s light duty truck fleet, both in the U.S. and international operations, is also owned.

The Company owns and leases regional and district facilities from which pressure pumping services and other oilfield services are provided to land-based and offshore customers. The Company’s principal executive offices in Houston, Texas are leased. The technology and research centers located near Houston, Texas and Calgary, Alberta are owned by the Company, as are blending facilities located in Germany, Singapore, U.S., Canada and Brazil. The Company owns and operates a calcium chloride manufacturing plant in Geismar, Louisiana for its completion fluids. This facility neutralizes hydrochloric acid with calcium carbonate, generating industrial strength, technical grade calcium chloride. The Company leases a 37,000 square foot facility in Mansfield, Texas that houses the manufacturing of some of the components used in its downhole completion tools. The Company operates several stimulation vessels including one in the North Sea, which is owned, four in South America and four in the Gulf of Mexico for which the hulls are leased. The Company believes that its facilities are adequate for its current operations. For additional information with respect to the Company’s lease commitments, see Note 10 of the Notes to Consolidated Financial Statements.

The Company, through performance of its service operations, is sometimes named as a defendant in litigation, usually relating to claims for bodily injuries or property damage (including claims for well or reservoir damage). The Company maintains insurance coverage against such claims to the extent deemed prudent by management. The Company believes that there are no existing claims that are likely to have a material adverse effect on the Company’s financial position or results of operations for which it has not already provided.

Through acquisition the Company assumed responsibility for certain claims and proceedings made against Western, Nowsco and OSCA in connection with their businesses. Some, but not all, of such claims and proceedings will continue to be covered under insurance policies of the Company’s predecessors that were in place at the time of the acquisitions. Although the outcome of the claims and proceedings against the Company (including Western, Nowsco and OSCA) cannot be predicted with certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on the Company’s financial position or results of operations for which it has not already provided.

On July 10, 2002, Chevron Phillips Chemical Company (“Chevron Phillips”) filed a lawsuit against BJ Services Company (“BJ”) for patent infringement in the United States District Court for the Southern District of Texas (Corpus Christi). The lawsuit relates to a patent issued in 1992 to the Phillips Petroleum Company (“Phillips”). This patent (the ‘477 patent) relates to a method for using enzymes to decompose used drilling mud. Although BJ has its own patents for remediating damage resulting from drill-in fluids (as opposed to drilling muds) in oil and gas formations (products and services for which are offered under the “Mudzyme” trademark), we approached Phillips for a license of the ‘477 patent. BJ was advised that Phillips had licensed this patent on an exclusive basis to Geo-Microbial Technologies, Inc. (“GMT”), a company co-owned by a former Phillips employee who is one of the inventors on the ‘477 patent, and that BJ should deal with GMT in obtaining a sublicense. BJ entered into a five year sublicense agreement with GMT in 1997.

Early in 2000, Phillips advised BJ that Phillips had reportedly terminated the license agreement between Phillips and GMT for GMT’s non-payment of royalties and that BJ’s sublicense had also been terminated. Even though BJ believes that its sublicense with GMT was not properly terminated and BJ’s Mudzyme treatments may not be covered by the ‘477 patent, in 2000, BJ stopped offering its enzyme product for use on drilling mud and drill-in fluids in the U.S. Nevertheless, Chevron Phillips is claiming that the use of enzymes in fracturing fluids and other applications in the oil and gas industry falls under the ‘477 patent. Further, even though their patent is valid only in the United States, Chevron Phillips is requesting that the court award it damages for BJ’s use of enzymes in foreign countries on the theory that oil produced from wells treated with enzymes is being imported into the United States.

The Company disputes Chevron Phillips’ interpretation of the ‘477 patent and its theory of damages, and has vigorously defended itself against the allegations. On November 25^th and 26^th of 2002, the Court conducted a hearing regarding the scope and the interpretation of the claims in the ‘477 patent. Following the hearing, the Court issued a ruling on March 16, 2003, which we believe interprets the ‘477 patent in a manner that is consistent with BJ’s position. Based on this ruling, BJ filed a Motion for Summary Judgment seeking a determination that fracturing fluids with enzymes do not come within the scope of the ‘477 patent. The Court granted this Motion on July 2, 2003. Subsequently, BJ filed a Motion for Summary Judgment relating to the use of Mudzymes outside of the United States. On September 22, 2003, the Court granted the Company’s Motion and dismissed this portion of the Chevron-Phillips’ case. We have been advised by Chevron Phillips that they will appeal these rulings to the Court of Appeals to the Federal Circuit. Although these rulings from the District Court have been favorable to the Company’s position, they could be overturned on appeal. Given the scope of these claims, the possibility of very costly litigation and even a substantial adverse verdict still exists. However, the Company does not presently believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or its results of operations.

On June 27, 2002, Halliburton Energy Services, Inc. filed suit against BJ and Weatherford International, Inc. for patent infringement in connection with drillable bridge plug tools. These tools are used to isolate portions of a well for stimulation work, after which the plugs are milled out using coiled tubing or a workover rig. Halliburton claims that tools offered by BJ (under the trade name “Python”) and Weatherford infringe two of its patents for a tool constructed of composite material. The lawsuit has been filed in the United States District Court for the Northern District of Texas (Dallas). Halliburton requested that the District Court issue a temporary restraining order and a preliminary injunction against both Weatherford and BJ to prevent either company from selling competing tools. On March 4, 2003, the District Court issued its opinion denying Halliburton’s requests. The Court denied Halliburton’s Motion to reconsider and Halliburton has filed an appeal with the Court of Appeals for the Federal Circuit.

The Company believes that the current design of the Python plug offered by BJ does not infringe any of the valid claims in the two Halliburton patents. The Company also believes that certain claims in the Halliburton patents are invalid based upon prior art demonstrated in products offered well before Halliburton filed for its patents. BJ’s revenue from the sale of its Python tools since the inception of this product in the summer of 2001 is approximately $4 million. The Company believes that it has no liability for infringement of the Halliburton patents. Moreover, even if the patents are found to be enforceable and the Company is found to have infringed them, the Company does not believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or its results of operations.

On March 17, 2000, BJ Services Company filed a lawsuit against Halliburton Energy Services in the United States District Court for the Southern District of Texas (Houston). In the lawsuit, BJ alleged that a well fracturing fluid system used by Halliburton infringes a patent issued to BJ in January 2000 for a method of well fracturing referred to by BJ as “Vistar^™”. This case was tried in March and April of 2002. The jury reached a verdict in favor of BJ on April 12, 2002. The jury determined that BJ’s patent was valid and that Halliburton’s competing fluid system, Phoenix, infringed the BJ patent. The District Court has entered a judgment for $101.1 million and a permanent injunction preventing Halliburton from using its Phoenix system. On August 6, 2003, a three-judge panel of the Court of Appeals for the Federal Circuit in Washington, D.C. unanimously affirmed the judgment in BJ’s favor. On October 17, 2003, the Federal Circuit denied Halliburton’s request for a re-hearing. Halliburton has 90 days from that date to seek review of this case by the U.S. Supreme Court. The Company has not recorded any income related to this case as of September 30, 2003 and will not do so until the judgment is final.

On April 4, 2002, a jury rendered a verdict adverse to OSCA in connection with litigation pending in the United States District Court for the Southern District of Texas (Houston). The lawsuit arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield Exploration. The jury determined that OSCA’s negligence caused or contributed to the blowout and that it was responsible for 86% of the damages suffered by Newfield. The total damage amount awarded to Newfield was $15.5 million (excluding pre- and post-judgement interest). The Court delayed entry of the final judgment in this case pending the completion of the related insurance coverage litigation filed by OSCA against certain of its insurers and its former insurance broker. The Court elected to conduct the trial of the insurance coverage issues based upon the briefs of the parties. In the interim, the related litigation filed by OSCA against its former insurance brokers for errors and omissions in connection with the policies at issue in this case was stayed. On February 28, 2003, the Court issued its Final Judgement in connection with the Newfield claims, based upon the jury’s verdict. The total amount of the verdict against OSCA is $15.6 million, inclusive of interest. At the same time, the Court issued its ruling on the related insurance dispute finding that OSCA’s coverage for this loss is limited to $3.8 million. Motions for New Trial have been denied by the Judge and the case is now on appeal to the U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. Great Lakes Chemical Corporation,

which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify BJ for 75% of any uninsured liability in excess of $3 million arising from the Newfield litigation. Taking this indemnity into account, the Company’s share of the uninsured portion of the verdict is approximately $5.7 million. The Company is fully reserved for its share of this liability.

Federal, state and local laws and regulations govern the Company’s operations of underground fuel storage tanks. Rather than incur additional costs to restore and upgrade tanks as required by regulations, management has opted to remove the existing tanks. The Company has completed the removal of these tanks and has remedial cleanups in progress related to the tank removals. In addition, the Company is conducting environmental investigations and remedial actions at current and former company locations and, along with other companies, is currently named as a potentially responsible party at four third-party owned waste disposal sites. An accrual of approximately $3.3 million has been established for such environmental matters, which is management’s best estimate of the Company’s portion of future costs to be incurred. Insurance is also maintained for environmental liabilities in amounts which the Company’s management believes are reasonable based on its knowledge of potential exposures.

The Company was notified on May 19, 2003, that misdemeanor criminal charges had been filed against it in connection with the illegal disposal of allegedly hazardous waste from its facility in Ardmore, Oklahoma. The Company’s investigation of this incident concluded that a former employee at the facility, a product handler, had removed drums from the facility in September of 2001, without instructions from, or the knowledge of the management of this location. The product handler provided a written statement to the investigating authorities in which he admitted having disposed of the drums without instructions from anyone at the Company and that he knew that his actions were prohibited under law. The charges that have been filed against the Company carry potential fines of $50,000. The Company does not believe that it is criminally responsible for the actions of this former employee and intends to defend itself from these charges. The Company has begun discussions with the prosecuting authorities in an effort to resolve this matter.

No matters were submitted for stockholders’ vote during the fourth quarter of the fiscal year ended September 30, 2003.

ITEM 5. Market for Registrant’s Common Equity and Related Stockholder Matters

The Common Stock of the Company began trading on The New York Stock Exchange in July 1990 under the symbol “BJS”. At December 5, 2003 there were approximately 3,469 holders of record of the Company’s Common Stock.

The following table sets forth for the periods indicated the high and low sales prices per share for the Company’s Common Stock reported on the NYSE composite tape:

Since its initial public offering in 1990, BJ Services has not paid any cash dividends to its stockholders. At September 30, 2003, there were 173,755,324 shares of Common Stock issued and 158,306,175 shares outstanding. On March 22, 2001, the Company’s Board of Directors approved a 2 for 1 stock split, which was effected on May 31, 2001 in the form of a stock dividend, for holders of record on May 17, 2001. On December 19, 1997, the Company’s Board of Directors authorized a stock repurchase program of up to $150 million (subsequently increased to $300 million in May 1998, to $450 million in September 2000, to $600 million in July 2001 and again to $750 million in October 2001). Repurchases are made at the discretion of the Company’s management and the program will remain in effect until terminated by the Company’s Board of Directors. Under this program, the Company has repurchased 12,792,800 shares at a cost of $219.4 million through fiscal 2000, 7,014,200 shares at a cost of $177.5 million during fiscal 2001, and 4,376,000 shares at a cost of $102.1 million in fiscal 2002. There were no such repurchases in fiscal 2003.

On April 24, 2002 the Company sold convertible senior notes with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). The notes are unsecured senior obligations that rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Company used the aggregate net proceeds of $400.1 million to fund a substantial portion of its acquisition of OSCA and for general corporate purposes. There was $414.9 million and $410.2 million outstanding under the convertible senior notes at September 30, 2003 and September 30, 2002, respectively.

The notes will mature in 2022 and cannot be called by the Company for three years after issuance. If the Company exercises its right to call the notes, the redemption price must be paid in cash. Holders of the notes can require the Company to repurchase the notes on the third, fifth, tenth and fifteenth anniversaries of the issuance. The Company has the option to pay the repurchase price in cash or stock. The issue price of the notes was $790.76 for each $1,000 in face value, which represents a yield to maturity of 1.625%. Of this 1.625% yield to maturity, 0.50% per year on the issue price will be paid in cash for the life of the security.

The notes are convertible into BJ Services common stock at an initial rate of 14.9616 shares for each $1,000 face amount note. This rate results in an initial conversion price of $52.85 per share (based on the purchaser’s original issue discount) and represents a premium of 45% over the April 18, 2002 closing sale price of the Company’s common stock on the New York Stock Exchange of $36.45 per share. The Company has the option and currently has the ability and the intent to settle notes that are surrendered for conversion using cash. Generally, except upon the occurrence of specified events, including a credit rating downgrade to below investment grade, holders of the notes are not entitled to exercise their conversion rights until the Company’s stock price is greater than a specified percentage (beginning at 120% and declining to 110% at the maturity of the notes) of the accreted conversion price per share. At September 30, 2003, the accreted conversion price per share would have been $53.56.

The Company has a Stockholder Rights Plan (the “Rights Plan”) designed to deter coercive takeover tactics and to prevent an acquirer from gaining control of the Company without offering a fair price to all of the Company’s stockholders. The Rights Plan was amended September 26, 2002, to extend the expiration date of the Rights to September 26, 2012 and increase the purchase price of the Rights. Under this plan, as amended, each outstanding share of Common Stock includes one-quarter of a preferred share purchase right (“Right”) that becomes exercisable under certain circumstances, including when beneficial ownership of Common Stock by any person, or group, equals or exceeds 15% of the Company’s outstanding Common Stock. Each Right entitles the registered holder to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock at a price of $520, subject to adjustment under certain circumstances. As a result of stock splits effected in the form of stock dividends in 1998 and 2001, one Right is associated with four outstanding shares of Common Stock. The purchase price for the one-fourth of a Right associated with one share of Common Stock is effectively $130. Upon the occurrence of certain events specified in the Rights Plan, each holder of a Right (other than an Acquiring Person) will have the right, upon exercise of such Right, to receive that number of shares of Common Stock of the Company (or the surviving corporation) that, at the time of such transaction, would have a market price of two times the purchase price of the Right. No shares of Series A Junior Participating Preferred Stock have been issued by the Company.

Information concerning securities authorized for issuance under equity compensation plans is set forth in the section entitled “Executive Compensation” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which section is incorporated herein by reference. Under the Company’s Employee Stock Purchase Plan 494,982 shares of Common Stock were issued at a price of $22.10 per share for the year ended September 30, 2003.

The following table sets forth certain selected historical financial data of the Company. The selected operating and financial position data as of and for each of the five years in the period ended September 30, 2003 have been derived from the audited consolidated financial statements of the Company, some of which appear elsewhere in this Annual Report. This information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto which are included elsewhere herein.

The Company’s worldwide operations are primarily driven by the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells, the number of well completions and the level of workover activity. Drilling activity, in turn, is largely dependent on the price of crude oil and natural gas. This situation often leads to volatility in the Company’s revenue and profitability, especially in the United States and Canada, where the Company historically has generated in excess of 50% of its revenue.

For the twelve months ended September 30, 2003, the active U.S. rig count averaged 966 rigs, an 11% increase from fiscal 2002. For the twelve months ended September 30, 2002, the active U.S. rig count averaged 870 rigs, a 26% decrease from fiscal 2001. Much of the decrease occurred in the number of rigs drilling for natural gas, which for fiscal 2002 decreased 23% from the previous fiscal year. The Company’s management believes that the average U.S. rig count for fiscal 2004 will be approximately 14% higher than fiscal 2003, essentially flat with current levels of approximately 1,100 rigs.

Drilling activity outside North America has historically been less volatile than drilling activity in the U.S. and Canada. Active international drilling rigs (excluding Canada) averaged 761 rigs during fiscal 2003, an increase of 4% from fiscal 2002. During 2002, active international drilling rigs (excluding Canada) averaged 730 rigs, a decrease of 1% from fiscal 2001. In Canada, drilling activity averaged 341 rigs during fiscal 2003, an increase of 29% from fiscal 2002. Canadian drilling activity declined in fiscal 2002 averaging 265 active drilling rigs, down 27% from the previous fiscal year. The Company expects international drilling activity outside of Canada to remain relatively flat for fiscal 2004 compared to fiscal 2003. Drilling activity in Canada is expected to increase approximately 5% for fiscal 2004 over fiscal 2003.

In May 2002, the SEC issued a proposed rule: “Disclosure in Management’s Discussion and Analysis about the Application of Critical Accounting Policies.” Although the SEC has not issued a final rule, the following discussion has been prepared on the basis of the guidelines in the SEC rule proposal. The proposed rule would require disclosures of critical accounting estimates. For an accounting policy to be deemed critical, the accounting policy must first include an estimate that requires a company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made. Second, different estimates that the company reasonably could have used for the accounting estimate in the current period, or changes in the accounting estimate that are reasonably likely to occur from period to period, must have a material impact on the presentation of the company’s financial condition or results of operations.

Estimates and assumptions about future events and their effects cannot be perceived with certainty. The Company bases its estimates on historical experience and on other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Materially different results can occur as circumstances change and additional information becomes known, including estimates not deemed “critical” under the proposed rule by the SEC. The Company believes the following are the most critical accounting policies used in the preparation of the Company’s consolidated financial statements and the significant judgments and uncertainties affecting the application of these policies. The selection of accounting estimates, including those deemed “critical,” and the associated disclosures in this discussion have been discussed by management with the Audit Committee of the Board of Directors. The critical accounting policies should be read in conjunction with the disclosures elsewhere in the Notes to the Consolidated Financial Statements. Significant accounting policies are discussed in Note 2 to the Consolidated Financial Statements.

Goodwill: Effective October 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 requires that goodwill no longer be amortized to earnings. SFAS 142 requires goodwill to be reviewed for possible impairment using fair value

measurement techniques on an annual basis, or if circumstances indicate that an impairment may exist. Specifically, goodwill impairment is determined using a two-step process. The first step of the goodwill impairment test compares the fair value of a reporting unit to its net book value, including goodwill. If the fair value of the reporting unit exceeds the net book value, no impairment is required and the second step is unnecessary. If the fair value of the reporting unit is less than the net book value, the second step is performed to determine the amount of the impairment, if any. Fair value measures include quoted market price, present value technique (estimate of future cash flows), and a valuation technique based on multiples of earnings or revenue. The second step compares the implied fair value of a reporting unit with the net book value of the reporting unit. If the net book value of a reporting unit exceeds the implied fair value, an impairment loss shall be recognized in the amount equal to that excess. The implied fair value is determined in the same manner as the amount of goodwill recognized in a business combination. That is, the fair value of the reporting unit is allocated to all the assets and liabilities as if the reporting unit had just been acquired in a business combination and the fair value of the reporting unit was the purchase price paid to acquire the reporting unit.

Determining fair value and the implied fair value of a reporting unit is judgmental and often involves the use of significant estimates and assumptions. These estimates and assumptions could have a significant impact on whether or not an impairment charge is recognized and also the magnitude of the impairment charge. The Company’s estimates of fair value are primarily determined using discounted cash flows. This approach uses significant assumptions such as a discount rate, growth rate, rig count, Company price book increases or decreases, and inflation rate.

During the first fiscal quarter of 2002, the Company performed a transitional fair value based impairment test utilizing discounted estimated cash flows to evaluate any possible impairment of goodwill, and determined that fair value exceeded the net book value at October 1, 2001, therefore no impairment loss has been recorded. No impairment adjustment was necessary to the Company’s $879.7 million goodwill balance at September 30, 2003. See Notes 2 and 8 of the Notes to the Consolidated Financial Statements for more information on goodwill and segments.

Pension Plans: Pension expense is determined in accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions.” In accordance with SFAS 87, the Company utilizes an estimated long-term rate of return on plan assets and any difference from the actual return is the unrecognized gain/loss which is amortized into earnings in future periods.

The Company determines the annual net periodic pension expense and pension plan liabilities on an annual basis using a third-party actuary. In determining the annual estimate of net periodic pension cost, the Company is required to make an evaluation of critical assumptions such as discount rate, expected long-term rate of return and expected increase in compensation levels. These assumptions may have an effect on the amount and timing of future contributions. Discount rates are based on high quality corporate fixed income investments. Long-term rate of return assumptions are based on actuarial review of the Company’s asset allocation and returns being earned by similar investments. The rate of increase in compensation levels is reviewed with the actuaries based upon our historical salary experience. The effects of actual results differing from our assumptions are accumulated and amortized over future periods, and, therefore, generally affect our recognized expense in future periods.

As with many companies, during 2002, actual asset returns for the Company’s pension assets were adversely impacted by the continued deterioration of the equity markets and declining interest rates. The negative asset returns and declining discount rates unfavorably affected the Company’s funded status. As a result, in calendar year 2004, the Company will have a minimum pension funding requirement of $11.1 million. We expect to fund this amount with cash flows from operating activities. In accordance with SFAS 87, the Company’s balance in other noncurrent liabilities for the U.S. minimum pension liability adjustments was $23.3 million and $23.2 million as of September 30, 2003 and 2002, respectively. The Company’s balance in other noncurrent liabilities for the foreign minimum pension liability adjustments was $22.9 million and $21.3 million as of September 30, 2003 and 2002, respectively. As there were no previously unrecognized prior service costs at

September 30, 2003 and 2002, the full amount of the adjustments, net of related deferred tax benefit, are reflected within Accumulated Other Comprehensive Income as a reduction of stockholders’ equity. See Note 9 to the Consolidated Financial Statements for more information on the Company’s pension plans.

Income Taxes: The effective income tax rates were 31.7%, 34.1%, and 34.0% for the years ended September 30, 2003, 2002, and 2001, respectively. These rates vary primarily due to fluctuations in taxes from the mix of domestic versus foreign income. Deferred tax assets and liabilities are recognized for differences between the book basis and tax basis of the net assets of the Company. In providing for deferred taxes, management considers current tax laws, estimates of future taxable income and available tax planning strategies. This process also involves making forecasts of current and future years’ United States taxable income. Unforeseen events and industry conditions may impact these forecasts which in turn can affect the carrying value of deferred tax assets and liabilities and impact our future reported earnings.

Self Insurance Accruals and Loss Contingencies: The Company is self-insured for certain losses relating to workers’ compensation, general liability, property damage and employee medical benefits for claims filed and claims incurred but not reported. Management reviews the liability on a quarterly basis. The liability is estimated on an undiscounted basis using individual case-based valuations and statistical analysis and is based upon judgment and historical experience; however, the final cost of many of these claims may not be known for five years or longer. This estimate is subject to trends, such as loss development factors, historical average claim volume, average cost for settled claims and current trends in claim costs. Significant and unanticipated changes in these trends or future actual payouts could result in additional increases or decreases to the recorded accruals. We have purchased stop-loss coverage in order to limit, to the extent feasible, our aggregate exposure to certain claims. There is no assurance that such coverage will adequately protect the Company against liability from all potential consequences. At September 30, 2003 and September 30, 2002, self-insurance accruals totaled $14.8 million and $12.3 million, respectively.

As discussed in Note 10 of the Consolidated Financial Statements, legal proceedings covering a wide range of matters are pending or threatened against the Company. It is not possible to predict the outcome of the litigation pending against the Company and litigation is subject to many uncertainties. It is possible that there could be adverse developments in these cases. The Company records provisions in the consolidated financial statements for pending litigation when we determine that an unfavorable outcome is probable and the amount of the loss can be reasonably estimated. While we believe that our accruals for these matters are adequate, if the actual loss from a loss contingency is significantly different than the estimated loss, our results of operations may be over or understated.

On May 31, 2002, the Company completed the acquisition of OSCA, a completion services (pressure pumping), completion tools and completion fluids company based in Lafayette, Louisiana, with operations primarily in the U.S. Gulf of Mexico, Brazil and Venezuela for a total purchase price of $470.6 million. On June 24, 2002, the Company completed a $9.1 million acquisition of the coiled tubing assets and business of Maritima Petroleo E Engenharia, LTDA (“Maritima”), a leading provider of coiled tubing services in Brazil. See Note 3 of the Notes to the Consolidated Financial Statements for additional information regarding these acquisitions.

On November 26, 2003, the Company completed the acquisition of Cajun Tubular Services, Inc. (“Cajun”) for a total purchase price of $8.1 million (net of cash). Cajun, located in Lafayette, Louisiana, provides tubular running, testing and torque monitoring services to the Gulf of Mexico market. This acquisition was accounted for using the purchase method of accounting.

On December 2, 2003, the Company acquired the assets and business of Petro-Drive, a division of Grant Prideco, Inc., for a total purchase price of $7 million. Petro-Drive, located in Lafayette, Louisiana, is a leading provider of hydraulic and diesel hammer services to the Gulf of Mexico market and select markets internationally. This acquisition was accounted for using the purchase method of accounting.

The following table sets forth selected key operating statistics reflecting industry rig count and the Company’s financial results:

Revenue and Operating Income: For year ended September 30, 2003, consolidated revenue increased 15%, compared to the same period last year with U.S./Mexico Pressure Pumping Services revenue increasing 9% and International Pressure Pumping Services revenue increasing 13%. Revenue from Other Oilfield Services was up 41% due primarily to the addition of the completion fluids and completion tools service lines acquired with OSCA in May 2002. For the year ended September 30, 2002, consolidated revenue decreased 16%, compared to year ended September 30, 2001 with U.S./Mexico Pressure Pumping Services revenue decreasing 26% and International Pressure Pumping Services decreasing 10%. Revenue from Other Oilfield Services was up 16% due primarily to the addition of the completion fluids and completion tools service lines acquired with OSCA in May 2002.

For the year ended September 30, 2003, operating income margins decreased to 13.7% from 14.1% reported for the year ended September 30, 2002, due primarily to lower U.S. pricing, which was partially offset by increased Canadian activity. For the year ended September 30, 2002, operating income margins declined to 14.1% from 24.6% reported for the year ended September 30, 2001, due primarily to activity and pricing declines in the U.S. and Canadian markets. See discussion below on individual segments for further revenue and operating income variance details.

Depreciation Expense: For the year ended September 30, 2003, depreciation expense increased by $15.3 million, compared to the year ended September 30, 2002. This is primarily a result of the Company’s capital spending levels and additional depreciation expense on certain capital improvements on leased equipment. For the year ended September 30, 2002, depreciation expense was consistent with the year ended September 30, 2001.

Goodwill Amortization: As a result of the Company’s adoption of SFAS 142, as described in Note 2 of the Notes to the Consolidated Financial Statements, goodwill amortization ceased in fiscal 2002, compared to $13.7 million in fiscal 2001.

Research and Engineering Expense, Marketing Expense, and General and Administrative Expense: For fiscal 2003 and 2002, research and engineering expense, marketing expense and general and administrative expense have remained relatively consistent as a percentage of consolidated revenue. For fiscal 2002 compared to fiscal 2001, these expenses in total increased $3.4 million primarily as a result of the acquisition of OSCA.

Other Expenses: Interest expense increased $7.0 million for the year ended September 30, 2003, compared to the year ended September 30, 2002. This is a result of the issuance of convertible debt in April 2002, used to finance a portion of the OSCA acquisition. Interest expense decreased $4.3 million for the year ended September 30, 2002, compared to the year ended September 30, 2001 as a result of lower average debt levels in fiscal 2002.

Interest income increased $0.1 million for the year ended September 30, 2003, compared to the year ended September 30, 2002. This is a result of an increased cash and cash equivalents balance. Interest income in fiscal 2002 was $2.0 million, compared to $2.6 million in fiscal 2001. This income is derived from investing excess cash from operating activities.

Other (Expense) Income, net: For the year ended September 30, 2003, compared to the year ended September 30, 2002, other expense, net increased $0.5 million. This is a result of gains from insurance recoveries in 2002. For the year ended September 30, 2002, compared to the year ended September 30, 2001, other income, net decreased $6.9 million. This was primarily as a result of a gain on the sale of an equity investment in 2001. For additional details of this account, see Note 12 of the Notes to the Consolidated Financial Statements.

Income Taxes: Primarily as a result of higher profitability in certain international jurisdictions where the statutory tax rate is less than the U.S. tax rate, the effective tax rate was 31.7% for the year ended September 30, 2003, compared with 34.1% for the year ended September 30, 2002. The effective tax rate was relatively constant between fiscal 2002 and 2001.

The U.S./Mexico Pressure Pumping segment primarily provides stimulation and cementing services to the petroleum industry in the U.S. and Mexico. Stimulation services are designed to improve the flow of oil and natural gas from producing formations. Cementing services consists of pumping a cement slurry into a well between the casing and the wellbore to isolate fluids that might otherwise damage the casing and/or affect productivity, or that could migrate to different zones, during the drilling and completion phase of a well. See “Business” included elsewhere in the Company’s 2003 Annual Report on Form 10-K for more information on these operations.

Revenue for fiscal 2003 was $982.6 million, an increase of $83.9 million, or 9.3% compared to fiscal 2002. Revenue increased due primarily to an 11% increase in U.S. drilling activity and increased market share, partially offset by lower U.S. prices in fiscal 2003 compared to fiscal 2002.

Operating income for fiscal 2003 was $190.3 million, an increase of $1.2 million, or 0.6% from fiscal 2002. Operating income increased as a result of activity increases, market share increases, and labor and equipment efficiencies. These increases were mostly offset by a deterioration in prices received by the Company for pressure pumping services compared to fiscal 2002. The decline resulting from our prices for pumping services occurred primarily in the first quarter of fiscal 2003.

Revenue was $898.7 million, a decrease of $320.7 million, or 26% compared to fiscal 2001. The decline was primarily due to decreased drilling and workover activity which declined 26%, compared to fiscal 2001. In addition, prices for the Company’s pressure pumping services in the U.S. market weakened in fiscal 2002.

Operating income was $189.1 million, a decrease of $236.0 million, or 55.5% compared to fiscal 2001. The decrease was due primarily to decreased revenue resulting from the decline in drilling and workover activity, along with the corresponding decline in prices for the Company’s products and services. The Company’s average U.S. pricing declined approximately 7% from fiscal 2001. Also contributing to the decline was increased labor costs as a percentage of revenue and higher depreciation resulting from the U.S. fleet recapitalization initiative, a program which began in late 1998 to rebuild and upgrade the Company’s core fleet of fracturing pumping units in the U.S.

The Company’s management believes that average U.S. rig count for fiscal 2004 will be approximately 14% higher than fiscal 2003, essentially flat with current levels at approximately 1,100 rigs.

The International Pressure Pumping segment primarily provides stimulation and cementing services to the petroleum industry outside of the U.S. and Mexico. Stimulation services are designed to improve the flow of oil and natural gas from producing formations. Cementing services consists of pumping a cement slurry into a well between the casing and the wellbore to isolate fluids that might otherwise damage the casing and/or affect productivity, or that could migrate to different zones, during the drilling and completion phase of a well. See “Business” included elsewhere in the Company’s 2003 Annual Report on Form 10-K for more information.

Revenue for fiscal 2003 was $801.8 million, an increase of $89.2 million, or 13% from fiscal 2002. In Canada, revenues increased 29% compared to fiscal 2002 with a corresponding 29% increase in the average active drilling rigs in Canada from fiscal 2002. During the first quarter of fiscal 2003, the activity increase was primarily in shallow drilling areas of Southern Canada as warm weather delayed rig movement into the North, an area with historically higher revenue per job. In addition, Canada had a favorable exchange rate effect as the U.S. dollar weakened against the Canadian dollar compared to fiscal 2002. Revenues in Russia increased 24% from fiscal 2002 due to revenues associated with service rigs acquired in the third quarter of fiscal 2002, partially offset by activity delays as a result of extremely cold weather during the first quarter of fiscal 2003. Asia Pacific revenue increased 8% from the prior fiscal year as a result of activity and market share increases in Malaysia and New Zealand. Europe and Africa revenue increased 12% from fiscal 2002 due to strong coiled tubing and cementing activity in Norway and Africa. Revenue in Latin America increased 2% over fiscal 2002 primarily as a result of increased market share in Brazil with the acquisition of Maritima in June 2002 and the commissioning of the Blue Shark stimulation vessel in April 2002. These increases in Latin America were mostly offset by declines in Venezuela as a result of the national labor strike. In addition, there were declines in India resulting from activity declines.

Operating income was $90.7 million, an increase of $18.6 million, or 26% from the 2002 fiscal year. While favorable foreign exchange rates in Canada increased revenue, they had minimal impact on operating income as most of our expenses are also denominated in Canadian dollars. The increase in operating income was primarily due to activity increases and improved labor and equipment utilization efficiencies. The headcount for year ended September 30, 2003 decreased 1% compared to fiscal 2002 with revenue increasing $89.2 million, or 13%.

Revenue for fiscal 2002 was $712.6 million, a decrease of $82.1 million, or 10.3% from fiscal 2001. The revenue decrease was largely attributable to the Company’s Canadian operations, with a 27% decrease in revenue corresponding to a 27% decline in drilling activity from fiscal 2001. The Company also had a decrease in revenue in Latin America of 19% as compared to fiscal 2001, due primarily to activity declines in Argentina and Venezuela as a result of political uncertainties and economic declines. Revenue from operations in the Eastern Hemisphere (which includes the Company’s operations in Europe and Africa, the Middle East, Asia Pacific, Russia and China) increased 5% from fiscal 2001, led by increases in the Middle East. Increased activity in India and Kazakhstan were the main contributors to the Middle East growth.

Operating income was $72.1 million, a decrease of $54.7 million, or 43% from fiscal 2001, primarily due to reduced activity in Canada and political uncertainties and economic declines in Argentina and Venezuela. In addition, there were approximately $4 million in combined costs from the devaluation of Argentina’s currency and severance costs incurred in connection with reductions in personnel in Canada and Latin America during the second quarter of fiscal 2002. The Eastern Hemisphere experienced a 4% decrease in operating income from fiscal 2001 primarily due to decreased profitability in the Europe and Africa region.

The Company expects international drilling activity outside of Canada to remain relatively flat for fiscal 2004 compared to fiscal 2003. Drilling activity in Canada is expected to increase approximately 5% for fiscal 2004 over fiscal 2003. Effective July 1, 2003, the Company implemented a price book increase of 5% in Canada, which will be phased in over the next several quarters. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures. Currently, most of our Canadian revenue generated is on the new price book.

The Other Oilfield Services segment consists of production chemicals, casing and tubular services, process and pipeline services, and with the acquisition of OSCA on May 31, 2002, completion tools and completion fluids services in the U.S. and select markets internationally. See “Business” included elsewhere in the Company’s 2003 Annual Report on Form 10-K for more information.

Revenue was $358.5 million, an increase of $104.8 million, or 41% when compared to fiscal 2002. The increase was due primarily to the addition of completion fluids and completion tools service lines acquired with OSCA on May 31, 2002. Other Oilfield Services revenue (excluding completion fluids and completion tools) increased 9%, primarily as a result of geographic expansion of our casing and tubular services and the process and pipeline services.

Operating income for the Company’s Other Oilfield Services segment was $49.9 million, an increase of $19.7 million, or 65% from prior year. The increase was due primarily to the addition of completion fluids and completion tools service lines acquired with OSCA on May 31, 2002. Other Oilfield Services operating income (excluding completion fluids and completion tools) increased 12.5%, primarily as a result of geographic expansion of our casing and tubular services and the process and pipeline services, which is consistent with the increase in revenue mentioned above.

Revenue was $253.7 million, an increase of $34.7 million, or 16% when compared to fiscal 2001. Approximately $32 million of the increase relates to the completion fluids and completion tools service lines acquired with OSCA, effective May 31, 2002. Other Oilfield Services revenue (excluding completion fluids and

completion tools) increased 3% in fiscal 2002 as compared to fiscal 2001. Casing and tubular service revenue increased by 15% through activity improvements and expansion in West Africa and the Middle East. The process and pipeline and production chemicals division revenue was flat compared to fiscal 2001.

Operating income for the Company’s Other Oilfield Services segment was $30.2 million, a decrease of $4.2 million, or 12% from prior year. Despite the increase in revenue, there were reduced profit margins in process and pipeline services operations combined with $1.7 million of costs associated with the acquisition of OSCA, consisting primarily of the disposal of completion tools deemed obsolete as a result of the combination. Other Oilfield Services operating income (excluding completion fluids and completion tools) decreased 11%, due to reduced profit margins in process and pipeline service operations.

We expect revenue for this segment to increase modestly in fiscal 2004, primarily attributable to expanded markets for the completion tools and completion fluids business.

The Company’s working capital increased $178.7 million at September 30, 2003 compared to September 30, 2002. Cash and cash equivalents increased $192.9 million, driven primarily by positive cash flow from operations. The Company’s long-term debt consists of fixed term instruments and therefore, cash and cash equivalents were not used to pay down debt in fiscal 2003. Accounts receivable increased $105.4 million and accounts payable increased $51.2 million as a result of increased activity. As a result of higher taxable income in 2003 and utilizing most of our net operating loss carryforwards, our current tax liability increased $40.5 million.

During the second fiscal quarter of 2002, the Company sold convertible senior notes and received gross proceeds of $408.4 million (see below discussion in Liquidity and Capital Resources). The Company used $400.1 million of the aggregate net proceeds to fund a substantial portion of the purchase price of its acquisition of OSCA on May 31, 2002.

The Company anticipates spending approximately $200 million in fiscal 2004, compared to $167 million spent in 2003 and $179 million spent in 2002. The 2004 capital expenditure program is expected to consist primarily of spending for the enhancement of the Company’s existing pressure pumping equipment, continued investment in the U.S. fracturing fleet recapitalization initiative and stimulation expansion internationally. The Company has made significant progress with the U.S. fleet recapitalization initiative, which is now approximately 65% complete. The actual amount of 2004 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and is expected to be funded by cash flows from operating activities.

In June 2001, the Company replaced its existing credit facility with a new $400 million committed line of credit (“Committed Credit Facility”). The Committed Credit Facility consists of a $200 million, 364-day commitment that renews annually at the option of the lenders and a $200 million three-year commitment. The current Committed Credit Facility expires in June 2004 and the Company expects to replace this facility during the year. There were no outstanding borrowings under the Committed Credit Facility at September 30, 2003.

In addition to the Committed Credit Facility, the Company had $119.7 million in various unsecured, discretionary lines of credit at September 30, 2003, which expire at the bank’s discretion. There are no

requirements for commitment fees or compensating balances in connection with these lines of credit, and interest on borrowings is based on prevailing market rates. There were $5.9 million and $3.5 million in outstanding borrowings under these lines of credit at September 30, 2003 and September 30, 2002, respectively.

In June 2001, the Company repurchased and retired $46 million of its 7% notes maturing in 2006 and recorded associated debt extinguishment costs of $1.7 million (classified as other expense), consisting mainly of a $1.3 million early payment premium. At September 30, 2003 and September 30, 2002, the Company had issued and outstanding $78.9 million of its 7% notes.

On April 24, 2002 the Company sold convertible senior notes with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). The notes are unsecured senior obligations that rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Company used the aggregate net proceeds of $400.1 million to fund a substantial portion of the purchase price of its acquisition of OSCA, which closed on May 31, 2002, and for general corporate purposes. There were $414.9 million and $410.2 million outstanding under the convertible senior notes at September 30, 2003 and September 30, 2002, respectively.

The notes will mature in 2022 and cannot be called by the Company for three years after issuance. If the Company exercises its right to call the notes, the redemption price must be paid in cash. Holders of the notes can require the Company to repurchase the notes on the third, fifth, tenth and fifteenth anniversaries of the issuance. The Company has the option to pay the repurchase price in cash or stock. The issue price of the notes was $790.76 for each $1,000 in face value, which represents an annual yield to maturity of 1.625%. Of this 1.625% yield to maturity, 0.50% per year on the issue price will be paid semi-annually in cash for the life of the security.

In calendar year 2004, the Company will have a minimum pension funding requirement of $11.1 million. This is expected to be funded by cash flows from operating activities.

The Company’s total debt (net of cash) was 11.9% of its total capitalization (total capitalization equals the sum of debt, net of cash and stockholders’ equity) at September 30, 2003, compared to 22.3% at September 30, 2002. The Committed Credit Facility includes various customary covenants and other provisions including the maintenance of certain profitability and solvency ratios, none of which materially restrict the Company’s activities. The Company is currently in compliance with all covenants imposed by the terms of its indebtedness. Management believes that the Committed Credit Facility, combined with other discretionary credit facilities and cash flows from operations, provide the Company with sufficient capital resources and liquidity to manage its routine operations, meet debt service obligations and fund projected capital expenditures. If the discretionary lines of credit are not renewed, or if borrowings under these lines of credit otherwise become unavailable, the Company expects to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

fee over a period of at least six years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $33.9 million and $47.8 million as of September 30, 2003 and September 30, 2002, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. The Company received partnership approval in September 2003 to substitute certain pumping service equipment and has accounted for it as an exchange of like-kind assets with no earnings impact since the earnings process has not yet culminated. As a result of the substitutions, the deferred gain was reduced by $9.2 million as of September 30, 2003. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million.

In 1997, the Company contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to the Company’s customers for which the Company pays a service fee over a period of at least eight years, but not more than 14 years of approximately $10 million annually. This is accounted for as an operating lease and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $16.0 million and $18.8 million as of September 30, 2003 and September 30, 2002, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. The Company received partnership approval in October 2003 to substitute certain pumping service equipment and has accounted for it as an exchange of like-kind assets with no earnings impact since the earnings process has not yet culminated. As a result of the substitutions, the deferred gain was reduced by $14.1 million subsequent to September 30, 2003. In June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million.

The following table summarizes the Company’s contractual cash obligations and other commercial commitments as of September 30, 2003 (in thousands):

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. When the liability is initially recorded, associated costs are capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 143 requires entities to record the cumulative effect of a change in accounting principle in the income statement in the period of adoption. The Company adopted SFAS 143 on October 1, 2002. The Company has an asset retirement obligation (“ARO”) with respect to machinery and equipment permanently affixed to the decks of certain leased vessels. The Company is obligated to remove the machinery and equipment and restore the vessel to its original condition upon returning the vessel to the owner. The Company determined the fair value of the ARO by using the “expected cash flow” approach and probability weighting multiple scenarios and related outcomes. The cumulative effect of the adoption of SFAS 143 had no effect on earnings per share. The ARO was $3.1 million at October 1, 2002. Due to the immaterial effects that this new standard had on a cumulative basis as of October 1, 2002 we are not presenting pro forma ARO disclosures. Based on our ARO’s as of October 1, 2003, on an annual basis, we expect depreciation expense to increase by approximately $0.1 million and to incur accretion expense of approximately $0.2 million as a result of adopting SFAS 143.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). SFAS 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS 144 supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of” and APB Opinion 30, while retaining many of the requirements of these two statements. Under SFAS 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from ongoing operations and the reporting entity will not have any significant continuing involvement in the discontinued operations prospectively. SFAS 144 is effective for fiscal years beginning after December 15, 2001. SFAS 144 did not materially change the methods used by the Company to measure impairment losses on long-lived assets but may result in future dispositions being reported as discontinued operations to a greater extent than is currently permitted. The Company adopted SFAS 144 on October 1, 2002.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities (“SFAS 146”). This standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. SFAS 146 replaces accounting guidance provided by EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

In November 2002, FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34” (“FIN 45”) was issued. The interpretation requires that upon issuance of a guarantee, the entity must recognize a liability for the fair value of the obligation it assumes under that obligation. This interpretation is intended to improve the comparability of financial reporting by requiring identical accounting for guarantees issued with separately identified consideration and guarantees issued without separately identified consideration. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The guarantor’s previous accounting for guarantees that were issued before the date of FIN 45’s

initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of FIN 45. The Company adopted FIN No. 45 on January 1, 2003. No liabilities were required to be recognized upon adoption and the Company’s current guarantees are disclosed in Note 10 of the Notes to the Consolidated Financial Statements.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123, Accounting for Stock-Based Compensation” (“SFAS 148”). This Statement amends SFAS 123, to provide alternative methods of transition for a voluntary change to the fair value-based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. This statement also requires that those effects be disclosed more prominently by specifying the form, content and location of those disclosures. SFAS 148 is intended to improve the prominence and clarity of the pro forma disclosures required by SFAS 123 by prescribing a specific tabular format and by requiring disclosure in the “Summary of Significant Accounting Policies” or its equivalent. In addition, this statement is intended to improve the timeliness of those disclosures by requiring their inclusion in financial reports for interim periods. SFAS 148 also amends certain disclosure requirements under APB 25. This statement is effective for financial statements for fiscal years ending after December 15, 2002 and is effective for financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. The Company did not adopt fair value based method of accounting for stock-based employee compensation; and therefore, adoption of SFAS 148 on January 1, 2003 impacted the disclosures only, not the financial results of the Company.

In January 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. FIN 46 applies to public enterprises as of the beginning of the applicable interim or annual period. The Company adopted FIN 46 on July 1, 2003. Adoption of the provisions of FIN 46 did not have a material impact on the Company’s financial position or results of operations.

In September 2003, the FASB issued an exposure draft regarding “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” It would not change the measurement or recognition of those plans required by existing accounting pronouncements; however, it would replace SFAS 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“SFAS 132”). If implemented as proposed, it would retain most of the disclosure requirements of SFAS 132 and would require additional disclosures about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. As proposed, the effective date would be for fiscal years after December 15, 2003. In addition, there would be additional disclosure requirements for interim-period financial reports for the first fiscal quarter of the year following initial application for the annual disclosure requirements. Since the exposure draft only revises disclosure requirements, it will not have a material impact on the Company’s financial position or results of operations.

A non-GAAP financial measure is a numerical measure of a registrant’s historical or future financial performance, financial position or cash flows that 1) excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the most directly comparable measure calculated and presented

in accordance with GAAP in the statement of income, balance sheet, or statement of cash flows, or 2) includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the most directly comparable measure so calculated and presented.

From time to time, the Company utilizes non-GAAP financial measures. The most common non-GAAP financial measures used by the Company include EBITDA, EBITDA margin, free cash flow, net debt, and net interest expense.

EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) is computed by starting with net income, adding income tax expense, adding interest expense, deducting interest income and adding depreciation and amortization. The most comparable GAAP measure is cash flow from operating activities as depicted in the Consolidated Statement of Cash Flows. EBITDA less income tax expense, less interest expense, plus interest income, plus or minus changes in working capital, plus minority interest, plus unearned compensation, plus deferred taxes reconciles to cash flow from operating activities. EBITDA margin is simply EBITDA as a percentage of revenue. Management believes EBITDA and EBITDA margin provide useful information to investors as they represent the measure of pre-tax cash flow of the Company, prior to debt service requirements.

Free cash flow is computed by starting with net income, adding depreciation and amortization and deducting capital expenditures. The most comparable GAAP measure is cash flow from operating activities. Free cash flow plus capital expenditures, plus changes in working capital, plus minority interest, plus unearned compensation, plus deferred taxes reconciles to cash flow from operating activities. Management believes free cash flow provides useful information to investors as it represents the cash, in excess of capital commitments, available to the Company to operate the business and meet non-discretionary expenditures.

Net debt and net interest expense are easily calculated from GAAP measures. Net debt is computed by adding short-term and long-term debt, less cash. Net interest expense is computed by subtracting interest income from interest expense.

This document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934 concerning, among other things, the Company’s prospects, expected revenue, expenses and profits, developments and business strategies for its operations, all of which are subject to certain risks, uncertainties and assumptions. These forward-looking statements are identified by their use of terms and phrases such as “expect,” “estimate,” “project,” “believe,” “achievable,” “anticipate” and similar terms and phrases. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to:

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those expected, estimated or projected. Other than as required under the Securities laws, the Company does not assume a duty to update these forward looking statements. This list of risk factors is not intended to be comprehensive. See “Risk Factors” included elsewhere in the Company’s Form 10-K for the fiscal year ending September 30, 2003.

The table below provides information about the Company’s market sensitive financial instruments and constitutes a “forward-looking statement.” The Company’s major market risk exposure is to foreign currency fluctuations internationally and changing interest rates, primarily in the United States, Canada and Europe. The Company’s policy is to manage interest rates through use of a combination of fixed and floating rate debt. If the floating rates were to increase by 10% from September 30, 2003 rates, the Company’s combined interest expense to third parties would increase by a total of $2,453 each month in which such increase continued. At September 30, 2003, the Company had issued fixed-rate debt of $493.8 million. These instruments are fixed-rate and, therefore, do not expose the Company to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by $20.9 million if interest rates were to decline by 10% from their rates at September 30, 2003.

Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. There were no such borrowings denominated in foreign currencies at September 30, 2003. When the Company believes prudent, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were four forward foreign exchange contracts entered as of September 30, 2003, each in the amount of $2.3 million. These contracts are being accounted for as cash flow hedges of future foreign currency denominated obligations. Beginning in November 2003 and ending in August 2004, one contract will settle in each of the following four quarters. The effect of these cash flow hedges as of September 30, 2003 on Accumulated Other Comprehensive Income was immaterial. All items described are non-trading and are stated in U.S. dollars (in thousands).

We have audited the accompanying consolidated statements of financial position of BJ Services Company and subsidiaries as of September 30, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2003. Our audits also included the financial statement schedule listed at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of BJ Services Company and subsidiaries at September 30, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for goodwill in 2002.

The Accompanying Notes are an Integral Part of These Consolidated Financial Statements

The Company consolidates all investments in which we own greater than 50 percent, or in which we control. All material intercompany balances and transactions are eliminated in consolidation. Investments in companies in which the Company’s ownership interest ranges from 20 to 50 percent and the Company exercises significant influence over operating and financial policies are accounted for using the equity method. Other investments are accounted for using the cost method.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from these estimates.

All references in these financial statements and footnotes to numbers of shares outstanding, earnings per share amounts and per share data, including stock option and stock purchase plan information, have been restated to reflect the 2 for 1 stock split that occurred on May 31, 2001.

Certain amounts for 2002 and 2001 have been reclassified in the accompanying consolidated financial statements to conform to the current year presentation.

Cash and cash equivalents: The Company considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents.

Allowance for doubtful accounts: The Company performs ongoing credit evaluations of our customers and adjusts credit limits based upon payment history and the customer’s current credit worthiness, as determined by our review of their current credit information. We continuously monitor collections and payments from our customers and maintain a provision for estimated uncollectible accounts based upon our historical experience and any specific customer collection issues that we have identified. While such credit losses have historically been within our expectations and the provisions established, we cannot give any assurances that we will continue to experience the same credit loss rates that we have in the past. The cyclical nature of our industry may affect our customers’ operating performance and cash flows, which could impact our ability to collect on these obligations. In addition, many of our customers are located in certain international areas that are inherently subject to risks of economic, political and civil instabilities, which may impact our ability to collect these accounts receivables.

Inventories: Inventories, which consist principally of (i) products which are consumed in the Company’s services provided to customers, (ii) spare parts for equipment used in providing these services and (iii) manufactured components and attachments for equipment used in providing services, are stated primarily at the lower of weighted-average cost or market. Cost primarily represents invoice costs. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory based primarily on its estimated forecast of product demand, market conditions, production requirements and technological developments. Significant or unanticipated changes to the Company’s forecasts could require additional provisions for excess or obsolete inventory.

Property: Property is stated at cost less amounts provided for permanent impairments and includes capitalized interest of $0.6 million, $2.7 million and $1.9 million for the years ended September 30, 2003, 2002 and 2001, respectively, on funds borrowed to finance the construction of capital additions. Depreciation is

generally provided using the straight-line method over the estimated useful lives of individual items. Leasehold improvements are amortized on a straight-line basis over the shorter of their estimated useful lives or the lease terms. The estimated useful lives are 10 to 30 years for buildings and leasehold improvements and range from 3 to 12 years for machinery and equipment. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives.

Additionally, the carrying values of these assets are reviewed for impairment 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 the Company to make long-term forecasts of its future revenue and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s 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.

Intangible assets: Goodwill represents the excess of cost over the fair value of the net assets of companies acquired in purchase transactions. Prior to fiscal year 2002, goodwill was amortized on a straight-line basis over periods ranging from 5 to 40 years. Effective October 1, 2001, the Company adopted Financial Accounting Standards Board Statement No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 requires that goodwill no longer be amortized to earnings. The Company ceased the amortization of goodwill beginning October 1, 2001. The Company performed a transitional fair value based impairment test utilizing discounted estimated cash flows to evaluate any possible impairment of goodwill, and determined that fair value exceeded the recorded amount at October 1, 2001, therefore no impairment loss has been recorded. SFAS 142 requires goodwill to be reviewed for possible impairment on an annual basis, or if circumstances indicate that an impairment may exist. No impairment adjustment was neccesary to the Company’s $879.7 million net goodwill balance at September 30, 2002 and 2003. The changes in the carrying amount of goodwill by reporting unit for the year ended September 30, 2003, are as follows (in thousands):

Patents are being amortized on a straight-line basis over their estimated useful lives, not to exceed 17 years. Intangible assets (other than goodwill), net of accumulated amortization were $3.5 million and $2.4 million at September 30, 2003 and 2002, respectively. The Company utilizes undiscounted estimated cash flows to evaluate any possible impairment of intangible assets. If such cash flows are less than the net carrying value of the intangible assets the Company records an impairment loss equal to the difference in discounted estimated cash flows and the net carrying value. The discount rate utilized is based on market factors at the time the loss is determined.

The following table provides pro forma results for the year ended September 30, 2001 as if the non-amortization provisions of SFAS 142 had been applied (in thousands, except per share amounts):

Income Taxes: The Company provides for income taxes in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. This calculation requires the Company to make certain estimates about our future operations. Changes in state, federal and foreign tax laws as well as changes in our financial condition could affect these estimates.

Valuation Allowance for Deferred Tax Assets: The Company records a valuation allowance to reduce its deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will expire before realization of the benefit or that future deductibility is not probable. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future.

Self Insurance Accruals: The Company is self-insured for certain losses relating to workers’ compensation, general liability, property damage and employee medical benefits for claims filed and claims incurred but not reported. The Company’s liability is estimated on an actuarial undiscounted basis using individual case-based valuations and statistical analysis and is based upon judgment and historical experience; however, the final cost of many of these claims may not be known for five years or longer. Management reviews the reserve on a quarterly basis. At September 30, 2003 and September 30, 2002, self-insurance accruals totaled $14.8 million and $12.3 million, respectively.

Contingencies: Contingencies are accounted for in accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS 5”). SFAS 5 requires that we record an estimated loss from a loss contingency when information available prior to the issuance of our financial statements indicates that it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements and the amount of the

loss can be reasonably estimated. Accounting for contingencies such as environmental, legal, and income tax matters requires the Company to use its judgment. While the Company believes that its accruals for these matters are adequate, if the actual loss from a loss contingency is significantly different than the estimated loss, our results of operations may be over or understated. For significant litigation, the Company accrues for its legal costs.

Environmental remediation and compliance: Environmental remediation costs are accrued based on estimates of known environmental exposures using currently available facts, existing environmental permits and technology and presently enacted laws and regulations. For sites where the Company is primarily responsible for the remediation, the Company’s estimates of costs are developed based on internal evaluations and are not discounted. Such accruals are recorded when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated. The accrual is 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. Where the Company has been identified as a potentially responsible party in a U.S. federal or state Superfund site, the Company accrues its share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste contributed to the site by the Company to the total volume of waste at the site.

Revenue Recognition: The Company’s revenue is composed of product sales, rental, service and other revenue. Products, rentals, and services are generally sold based on fixed or determinable priced purchase orders or contracts with the customer. The Company recognizes revenue from product sales when title passes to the customer, the customer assumes risks and rewards of ownership, and collectibility is reasonably assured. Rental, service and other revenue is recognized when the services are provided and collectibility is reasonably assured.

Research and development expenditures: Research and development expenditures are charged to income as incurred.

Maintenance and repairs: Expenditures for maintenance and repairs are expensed as incurred. Expenditures for renewals and improvements are capitalized if they extend the life, increase the capacity, or improve the efficiency of the asset.

Foreign currency translation: The Company’s functional currency is primarily the U.S. dollar. Gains and losses resulting from financial statement translation of foreign operations where the U.S. dollar is not the functional currency are included in the consolidated statement of operations as cost of sales. Gains and losses resulting from financial statement translation of foreign operations where a foreign currency is the functional currency are included as a separate component of stockholders’ equity. The Company’s operations in Canada and Hungary use their respective local currencies as the functional currency.

Derivative instruments: The Company sometimes enters into forward foreign exchange contracts to hedge the impact of currency fluctuations on certain transactions and assets and liabilities denominated in foreign currencies. We do not enter into derivative instruments for speculative or trading purposes. SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended, requires that the Company recognize all derivatives on the balance sheet at fair value. Any ineffective portion of a derivative’s change in fair value is recognized into earnings. The Company designates and documents the derivative instrument as a cash flow hedge at its inception. The derivative is assessed to determine if the hedge is highly effective in offsetting changes in cash flows of the hedged item at inception and on an ongoing basis.

Employee stock-based compensation: Under SFAS No. 123 “Accounting for Stock-Based Compensation,” the Company is permitted to either record expenses for stock options and other stock-based employee compensation plans based on their fair value at the date of grant or to continue to apply Accounting Principles

Board Opinion No. 25 (“APB 25”) and recognize compensation expense, if any, based on the intrinsic value of the equity instruments at the measurement dates. The Company elected to continue following APB 25; therefore, no compensation expense has been recognized because the exercise prices of employee stock options equal the market prices of the underlying stock on the dates of grant.

The following pro forma table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 to the Stock Option Plan and the Stock Purchase Plan (in thousands, except per share amounts):

The pro forma compensation expense determined under SFAS 123 was calculated using the Black-Scholes option pricing model with the following assumptions:

In fiscal 2002, the Company changed its method of estimating future volatility for purposes of valuing its stock options and shares underlying the employee stock purchase plan. The Company calculated its volatility using historical daily, weekly and monthly price intervals to generate a reasonable range of expected future volatility, and used a factor at the low end of the range in accordance with SFAS 123.

New accounting pronouncements: In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. When the liability is initially recorded,

associated costs are capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 143 requires entities to record the cumulative effect of a change in accounting principle in the income statement in the period of adoption. The Company adopted SFAS 143 on October 1, 2002. The Company has an asset retirement obligation (“ARO”) with respect to machinery and equipment permanently affixed to the decks of certain leased vessels. The Company is obligated to remove the machinery and equipment and restore the vessel to its original condition upon returning the vessel to the owner. The Company determined the fair value of the ARO by using the “expected cash flow” approach and probability weighting multiple scenarios and related outcomes. The cumulative effect of the adoption of SFAS 143 had no effect on earnings per share. The ARO was $3.1 million at October 1, 2002. Due to the immaterial effects that this new standard had on a cumulative basis as of October 1, 2002, we are not presenting pro forma ARO disclosures. Based on our ARO’s as of October 1, 2003, on an annual basis, we expect depreciation expense to increase by approximately $0.1 million and to incur accretion expense of approximately $0.2 million as a result of adopting SFAS 143.

of the guarantor’s fiscal year-end. The guarantor’s previous accounting for guarantees that were issued before the date of FIN 45’s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of FIN 45. The Company adopted FIN No. 45 on January 1, 2003. No liabilities were required to be recognized upon adoption and the Company’s current guarantees are disclosed in Note 10 of the Notes to the Consolidated Financial Statements.

OSCA: On May 31, 2002, the Company completed the acquisition of OSCA, Inc. (“OSCA”) for a total purchase price of $470.6 million (including transaction costs). This acquisition was accounted for using the purchase method of accounting. Accordingly, the results of OSCA’s operations are included in the consolidated statement of operations beginning June 1, 2002. The assets and liabilities of OSCA have been recorded in the Company’s consolidated statement of financial position at estimated fair market value as of May 31, 2002 with the remaining purchase price reflected as goodwill.

The following table reflects (in thousands, except per share amounts) the Company’s results of operations on a pro forma basis as if the acquisition had been completed at the beginning of the periods presented utilizing OSCA’s historical results. This unaudited pro forma information excludes the effects of cost elimination and reduction initiatives directly related to the acquisition.

The pro forma financial information is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at the beginning of the periods presented, nor are they necessarily indicative of future operating results.

The Company has completed its review and determination of the fair values of the assets acquired. The allocation of the purchase price and estimated goodwill are summarized as follows (in thousands):

Other: On June 24, 2002, the Company completed a $9.1 million acquisition of the coiled tubing assets and business of Maritima Petroleo E Engenharia, LTDA (“Maritima”), a leading provider of coiled tubing services in Brazil. This acquisition was accounted for using the purchase method of accounting.

The Company made other acquisitions in fiscal 2001 for aggregate consideration of $29.0 million. These acquisitions were accounted for using the purchase method of accounting and, accordingly, any excess of total consideration over the estimated fair value of net assets acquired was recorded as goodwill. These acquisitions are not material to the Company’s financial statements and therefore pro forma information is not presented.

Basic Earnings Per Share (“EPS”) excludes dilution and is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is based on the weighted-average number of shares outstanding during each period and the assumed exercise of dilutive instruments (stock options, the stock purchase plan and the stock incentive plan) less the number of treasury shares assumed to be purchased from the proceeds using the average market price of the Company’s common stock for each of the periods presented. No dilutive effect has been included for the convertible senior notes issued April 24, 2002 (See Note 5) because the Company currently has the ability and intent to settle the conversion price in cash.

The following table presents information necessary to calculate earnings per share for the three years ended September 30, 2003 (in thousands, except per share amounts):

Long-term debt at September 30, 2003 and 2002 consisted of the following (in thousands):

On April 24, 2002 the Company sold convertible senior notes with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). The notes are unsecured senior obligations that rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Company used the aggregate net proceeds of $400.1 million to fund a substantial portion of the purchase price of its acquisition of OSCA, which closed on May 31, 2002, and for general corporate purposes. There were $414.9 million and $410.2 million outstanding under the convertible senior notes at September 30, 2003 and September 30, 2002, respectively.

The notes will mature in 2022 and cannot be called by the Company for three years after issuance. If the Company exercises its right to call the notes, the redemption price must be paid in cash. Holders of the notes can require the Company to repurchase the notes on the third, fifth, tenth and fifteenth anniversaries of the issuance. The Company has the option to pay the repurchase price in cash or stock. The issue price of the notes was $790.76 for each $1,000 in face value, which represents an annual yield to maturity of 1.625%. Of this 1.625% yield to maturity, 0.50% per year on the issue price will be paid semi-annually in cash for the life of the security.

In June 2001, the Company replaced its existing credit facility (the “Bank Credit Facility”) with a $400 million committed line of credit (the “Committed Credit Facility”). In connection with the replacement of the Bank Credit Facility, the Company prepaid $30.3 million of borrowings that were outstanding under the term loan portion and accelerated recognition of $1.2 million of unamortized debt issuance costs (classified as interest expense). The Committed Credit Facility consists of a $200 million, 364-day commitment that renews annually at the option of the lenders, and a $200 million, three-year commitment. The 364-day commitment that expired in June 2003 was renewed for an additional 364 days. Interest on outstanding borrowings is charged based on prevailing market rates, which were 1.79% and 2.42% at September 30, 2003 and 2002, respectively. The Company is charged various fees in connection with the Committed Credit Facility, including a commitment fee based on the average daily unused portion of the commitment. Commitment fees were $496,000, $493,000 and $383,000 for 2003, 2002 and 2001, respectively. There were no outstanding borrowings under the Committed Credit Facility at September 30, 2003 and 2002.

In addition to the Committed Credit Facility, the Company had $119.7 million of unsecured, discretionary lines of credit at September 30, 2003, which expire at the bank’s discretion. There are no requirements for commitment fees or compensating balances in connection with these lines of credit and interest is at prevailing market rates. There was $5.9 million and $3.5 million in outstanding borrowings under these lines of credit at September 30, 2003 and 2002, respectively. The weighted average interest rates on short-term borrowings outstanding as of September 30, 2003 and 2002 were 5.00% and 5.75%, respectively.

The Company’s debt agreements contain various customary covenants including maintenance of certain profitability and solvency ratios, as defined in the Committed Credit Facility, none of which materially restrict the Company’s activities. The Company is currently in compliance with all covenants imposed by the terms of its indebtedness.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable.

Cash and Cash Equivalents, Trade Receivables, Trade Payables, Short-Term Borrowings and Foreign Exchange Contracts: The carrying amount approximates fair value because of the short maturity of those instruments.

Long-term Debt: Fair value is based on the rates currently available to the Company for debt with similar terms and average maturities.

Foreign Exchange Contracts: Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. There were no such borrowings denominated in foreign currencies at September 30, 2003. When necessary, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were four forward foreign exchange contracts as of September 30, 2003, each in the amount of $2.3 million. These contracts are being accounted for as cash flow hedges of future foreign currency denominated obligations. Beginning in November 2003 and ending in August 2004, one contract will settle in each of the following four quarters. The effect of these cash flow hedges as of September 30, 2003 on Accumulated Other Comprehensive Income was not material. All items described are non-trading and are stated in U.S. dollars (in thousands).

The fair value of financial instruments that differed from their carrying value at September 30, 2003 and 2002 was as follows (in thousands):

The geographical sources of income before income taxes for the three years ended September 30, 2003 were as follows (in thousands):

The provision for income taxes for the three years ended September 30, 2003 is summarized below (in thousands):

The consolidated effective income tax rates (as a percent of income (loss) before income taxes) for the three years ended September 30, 2003 varied from the United States statutory income tax rate for the reasons set forth below:

Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of assets or liabilities and its reported amount in the financial statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rules currently in effect in each of the taxing jurisdictions in which the Company has operations. Generally, deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related asset or liability for financial reporting. The estimated deferred tax effect of temporary differences and carryforwards as of September 30, 2003 and 2002 were as follows (in thousands):

At September 30, 2003, the Company had approximately $30.2 million of foreign tax net operating loss carryforwards. The potential impact of the foreign net operating loss carryforwards subject to expiration has been reflected in the asset valuation allowance balance as of September 30, 2003. The Company’s valuation allowance was recorded as a part of the respective allocations of purchase price for various business acquisitions. Reversal of this valuation allowance will not effect the Company’s effective tax rate but instead would be recorded as a reduction of the goodwill attributable to the respective acquisition.

No deferred U.S. income tax liability has been recognized on undistributed earnings of foreign subsidiaries as they have been deemed permanently invested outside the U.S. If these earnings were to be remitted to the Company, any U.S. income taxes payable would be substantially reduced by foreign tax credits generated by repatriation of the earnings.

The alternative minimum tax credit carryforward is available to offset future federal income tax liabilities. The alternative minimum tax credit has no expiration date.

The Company currently has thirteen operating segments for which separate financial information is available and that have separate management teams that are engaged in oilfield services. The results for these operating segments are evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assessing performance. The operating segments have been aggregated into three reportable segments: U.S./Mexico Pressure Pumping, International Pressure Pumping and Other Oilfield Services.

The U.S./Mexico Pressure Pumping has two operating segments and includes cementing services and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tool services) provided throughout the United States and Mexico. These two operating segments have been aggregated into one reportable segment because they offer the same type of services, have similar economic characteristics, have similar production processes and use the same methods to provide their services.

The International Pressure Pumping segment has six operating segments. Similar to U.S./Mexico Pressure Pumping, it includes cementing and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tool services). These services are provided to customers in more than 50 countries in the major international oil and natural gas producing areas of Canada, Latin America, Europe, Africa, Southeast Asia, the Middle East, Russia and China. The operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer the same type of services, have similar production processes and use the same methods to provide their services. They also serve the same or similar customers. Customers include major multi-national, independent and national or state-owned oil companies.

The Other Oilfield Services segment has five operating segments. These operating segments provide other oilfield services such as production chemicals, casing and tubular services and process and pipeline services and, with the acquisition of OSCA on May 31, 2002, completion tools and completion fluids services in the U.S. and in select markets internationally. The operating segments have been aggregated into one reportable segment as they all provide other oilfield services, serve same or similar customers and some of the operating segments share equipment.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates the performance of its segments based on operating income. Intersegment sales and transfers are not material.

Summarized financial information concerning the Company’s segments for each of the three years ended September 30, 2003 is shown in the following tables (in thousands). The “Corporate” column includes corporate expenses not allocated to the operating segments. For the years ended September 30, 2003, 2002 and 2001, there was no revenue attributable to one customer that accounted for more than 10% of total revenue.

A reconciliation from the segment information to consolidated income before income taxes for each of the three years ended September 30, 2003 is set forth below (in thousands):

The Company administers a thrift plan for U.S. based employees whereby eligible employees elect to contribute from 2% to 20% of their base salaries to an employee benefit trust. Employee contributions are matched by the Company at the rate of $.50 per $1.00 up to 6% of the employee’s base salary. In addition, the Company contributes between 2% and 5% of each employee’s base salary depending on their age as of January 1 each year as a base contribution. Company matching contributions vest immediately while Company base contributions become fully vested after five years of employment. The Company’s employees formerly employed by OSCA (See Note 3) are covered under a savings plan which was merged into the Company’s thrift plan effective August 1, 2002. The Company’s contributions to these thrift plans amounted to $11.4 million, $10.6 million, and $8.4 million, in 2003, 2002, and 2001, respectively.

Effective October 1, 2000, the Company established a non-qualified supplemental executive retirement plan. The unfunded defined benefit plan will provide Company executives with supplemental retirement benefits based on the highest consecutive three years compensation out of the final ten years and become vested at age 55. The expense associated with this plan was $3.4 million, $4.0 million, and $3.7 million in 2003, 2002, and 2001, respectively. The related accrued benefit obligation was $10.0 million and $7.3 million as of September 30, 2003 and 2002, respectively.

Effective December 7, 2000, the Company established a non-qualified directors’ benefit plan. The unfunded defined benefit plan will provide the Company’s non-employee directors with benefits upon termination of their service based on the number of years of service and the last annual retainer fee. The expense associated with this plan was $.3 million, $.1 million and $1.3 million for 2003, 2002, and 2001, respectively. The related accrued benefit obligation was $1.7 million and $1.4 million as of September 30, 2003 and 2002, respectively.

The Company’s U.S. employees formerly employed for at least one year by The Western Company of North America (“Western”) are covered under a defined benefit pension plan as a carryover from the Company’s acquisition of Western. Pension benefits are based on years of service and average compensation for each employee’s five consecutive highest paid years during the last ten years worked. Benefits under the Western plan were frozen effective December 31, 1995, at which time all earned benefits were vested. The U.S. pension plan assets are primarily invested in U.S. equities and fixed income securities. The Company funds its pension plans with the amounts necessary to meet the minimum funding requirements under the Employee’s Retirement Income Security Act, as amended. The funded status of this plan at September 30, 2003 and 2002 was as follows (in thousands):

In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” the Company’s balance in other noncurrent liabilities for the minimum pension liability adjustments was $23.3 million and $23.2 million as of September 30, 2003 and 2002, respectively. As there were no previously unrecognized prior service costs at September 30, 2003 and 2002, the full amount of the adjustments, net of related deferred tax benefit, are reflected within Accumulated Other Comprehensive Income as a reduction of stockholders’ equity. See Note 12 for disclosure of the amounts included in other comprehensive income. In calendar year 2004, the Company will have a minimum pension funding requirement of $5.9 million. This is expected to be funded by cash flows from operating activities.

Assumptions used in accounting for the Company’s U.S. defined benefit pension plan with the measurement date as of September 30, were as follows:

Costs for each of the three years ended September 30, 2003 for the Company’s U.S. defined benefit plan were as follows (in thousands):

The Company sponsors defined benefit pension plans that cover substantially all employees in Canada and the United Kingdom (“UK”). The Canadian pension plan assets are primarily invested in fixed income securities

and Canadian equities, with the remaining balance invested in U.S. equities, international equities and short-term securities. The UK pension plan assets are primarily invested in UK equities and fixed income securities.

The funded status of the Company’s international plans at September 30, 2003 and 2002, on a combined basis, was as follows (in thousands):

In calendar year 2004, the Company will have a minimum pension funding requirement of $5.2 million. This is expected to be funded by cash flows from operating activities.

The following is a reconciliation of the benefit obligation and plan assets of the Company’s international defined benefit plans, on a combined basis (in thousands):

Assumptions used in accounting for the Company’s international defined benefit pension plans with a measurement date as of September 30, were as follows:

Combined costs for the Company’s international defined benefit plans for the three years ended September 30, 2003 were as follows (in thousands):

The Company sponsors plans that provide certain health care and life insurance benefits for retired employees (primarily U.S.) who meet specified age and service requirements, and their eligible dependents. These plans are unfunded and the Company retains the right, subject to existing agreements, to modify or eliminate them.

The Company’s postretirement medical benefit plan provides credits based on years of service that can be used to purchase coverage under the active employee plans. This plan effectively caps the Company’s health care inflation rate at a 4% increase per year. The 1995 reduction in the accumulated postretirement benefit obligation of approximately $5.7 million due to this cap was amortized over the average period of future service to the date of full eligibility for such postretirement benefits of the active employees. The amount was fully amortized as of September 30, 2000. In 2002, the Company provided additional employer contributions, above the 4% cap, for covered retirees in order to reduce the level of required retiree contributions. These additional contributions were a deviation from the substantive plan for 2002 only and resulted in an additional $.2 million in net periodic post retirement benefits and cost for the fiscal year ended September 30, 2002.

Net periodic postretirement benefit costs for the three years ended September 30, 2003 included the following components (in thousands):

The actuarial and recorded liabilities for these postretirement benefits were as follows at September 30, 2003 and 2002 (in thousands):

The following provides a reconciliation of the benefit obligation (in thousands):

The accumulated postretirement benefit obligation at September 30, 2003 and 2002 was determined using a discount rate of 5.85% and 6.50%, respectively, and a health care cost trend rate of 4%, reflecting the cap described above. Increasing the assumed health care cost trend rates by one percentage point would not have a material impact on the accumulated postretirement benefit obligation or the net periodic postretirement benefit cost because these benefits are effectively capped by the Company.

Through acquisition the Company assumed responsibility for certain claims and proceedings made against the Western Company of North America, Nowsco Well Service Ltd. and OSCA in connection with their businesses. Some, but not all, of such claims and proceedings will continue to be covered under insurance policies of the Company’s predecessors that were in place at the time of the acquisitions. Although the outcome of the claims and proceedings against the Company (including Western, Nowsco and OSCA) cannot be predicted with certainty, management believes that there are no existing claims or proceedings that are likely to have a material adverse effect on the Company’s financial position or results of operations for which it has not already provided.

On July 10, 2002, Chevron Phillips Chemical Company (“Chevron Phillips”) filed a lawsuit against BJ Services Company (“BJ”) for patent infringement in the United States District Court for the Southern District of Texas (Corpus Christi). The lawsuit relates to a patent issued in 1992 to the Phillips Petroleum Company (“Phillips”). This patent (the ‘477 patent) relates to a method for using enzymes to decompose used drilling mud. Although BJ has its own patents for remediating damage resulting from drill-in fluids (as opposed to drilling muds) in oil and gas formations (products and services for which are offered under the “Mudzyme” trademark), the Company approached Phillips for a license of the ‘477 patent. BJ was advised that Phillips had licensed this patent on an exclusive basis to Geo-Microbial Technologies, Inc. (“GMT”), a company co-owned by a former Phillips employee who is one of the inventors on the ‘477 patent, and that BJ should deal with GMT in obtaining a sublicense. BJ entered into a five year sublicense agreement with GMT in 1997.

The Company disputes Chevron Phillips’ interpretation of the ‘477 patent and its theory of damages, and has vigorously defended itself against the allegations. On November 25^th and 26^th of 2002, the Court conducted a hearing regarding the scope and the interpretation of the claims in the ‘477 patent. Following the hearing, the Court issued a ruling on March 16, 2003, which we believe interprets the ‘477 patent in a manner that is consistent with BJ’s position. Based on this ruling, BJ filed a Motion for Summary Judgment seeking a determination that fracturing fluids with enzymes do not come within the scope of the ‘477 patent. The Court granted this Motion on July 2, 2003. Subsequently, BJ filed a Motion for Summary Judgment relating to the use of Mudzymes outside of the United States. On September 22, 2003, the Court granted the Company’ Motion and dismissed this portion of the Chevron Phillips’ case. We have been advised by Chevron Phillips that they will appeal these rulings to the Court of Appeals to the Federal Circuit. Although these rulings from the District Court have been favorable to the Company’s position, they could be overturned on appeal. Given the scope of these claims, the possibility of very costly litigation and even a substantial adverse verdict still exists. However, the Company does not presently believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or results of operations.

well for stimulation work, after which the plugs are milled out using coiled tubing or a workover rig. Halliburton claims that tools offered by BJ (under the trade name “Python”) and Weatherford infringe two of its patents for a tool constructed of composite material. The lawsuit has been filed in the United States District Court for the Northern District of Texas (Dallas). Halliburton requested that the District Court issue a temporary restraining order and a preliminary injunction against both Weatherford and BJ to prevent either company from selling competing tools. On March 4, 2003, the District Court issued its opinion denying Halliburton’s requests. The Court denied Halliburton’s Motion to reconsider and Halliburton has filed an appeal with the Court of Appeals for the Federal Circuit.

The Company believes that the current design of the Python plug offered by BJ does not infringe any of the valid claims in the two Halliburton patents. The Company also believes that certain claims in the Halliburton patents are invalid based upon prior art demonstrated in products offered well before Halliburton filed for its patents. BJ’s revenue from the sale of its Python tools since the inception of this product in the summer of 2001 is approximately $4 million. The Company believes that it has no liability for infringement of the Halliburton patents. Moreover, even if the patents are found to be enforceable and the Company is found to have infringed it, the Company does not believe it is likely that the results of this litigation will have a material adverse impact on the Company’s financial position or the results of operations.

On March 17, 2000, BJ Services Company filed a lawsuit against Halliburton Energy Services in the United States District Court for the Southern District of Texas (Houston). In the lawsuit, BJ alleged that a well fracturing fluid system used by Halliburton infringes a patent issued to BJ in January 2000 for a method of well fracturing referred to by BJ as “Vistar^™”. This case was tried in March and April of 2002. The jury reached a verdict in favor of BJ on April 12, 2002. The jury determined that BJ’s patent was valid and that Halliburton’s competing fluid system, Phoenix, infringed the BJ patent. The District Court has entered a judgment for $101.1 million and a permanent injunction preventing Halliburton from using its Phoenix system. On August 6, 2003, a three-judge panel of the Court of Appeals for the Federal Circuit in Washington, D.C. unanimously affirmed the judgment in BJ’s favor. On October 17, 2003, the Federal Circuit denied Halliburton’s request for a re-hearing. Halliburton has 90 days from that date to seek review of this case by the U.S. Supreme Court. As of September 30, 2003 the Company has not recorded any income related to this case and will not do so until the judgment is final.

On April 4, 2002, a jury rendered a verdict adverse to OSCA in connection with litigation pending in the United States District Court for the Southern District of Texas (Houston). The lawsuit arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield Exploration. The jury determined that OSCA’s negligence caused or contributed to the blowout and that it was responsible for 86% of the damages suffered by Newfield. The total damage amount awarded to Newfield was $15.5 million (excluding pre- and post-judgement interest). The Court delayed entry of the final judgment in this case pending the completion of the related insurance coverage litigation filed by OSCA against certain of its insurers and its former insurance broker. The Court elected to conduct the trial of the insurance coverage issues based upon the briefs of the parties. In the interim, the related litigation filed by OSCA against its former insurance brokers for errors and omissions in connection with the policies at issue in this case has been stayed. On February 28, 2003, the Court issued its Final Judgement in connection with the Newfield claims, based upon the jury’s verdict. The total amount of the verdict against OSCA is $15.6 million, inclusive of interest. At the same time, the Court issued its ruling on the related insurance dispute finding that OSCA’s coverage for this loss is limited to $3.8 million. Motions for New Trial have been denied by the Judge and the case is now on appeal to the U.S. Court of Appeals for the Fifth Circuit,

both with regard to the liability case and the insurance coverage issues. Great Lakes Chemical Corporation, which formerly owned the majority of the outstanding shares of OSCA, has agreed to indemnify BJ for 75% of any uninsured liability in excess of $3 million arising from the Newfield litigation. Taking this indemnity into account, the Company’s share of the uninsured portion of the verdict is approximately $5.7 million. The Company is fully reserved for its share of this liability.

Federal, state and local laws and regulations govern the Company’s operation of underground fuel storage tanks. Rather than incur additional costs to restore and upgrade tanks as required by regulations, management has opted to remove the existing tanks. The Company has completed the removal of these tanks and has remedial cleanups in progress related to the tank removals. In addition, the Company is conducting environmental investigations and remedial actions at current and former company locations and, along with other companies, is currently named as a potentially responsible party at four third-party owned waste disposal sites. An accrual of approximately $3.3 million has been established for such environmental matters, which is management’s best estimate of the Company’s portion of future costs to be incurred. Insurance is also maintained for environmental liabilities in amounts which the Company’s management believes are reasonable based on its knowledge of potential exposures.

The Company was notified on May 19, 2003, that misdemeanor criminal charges had been filed against it in connection with the illegal disposal of allegedly hazardous waste from its facility in Ardmore, Oklahoma. The Company’s investigation of this incident concluded that a former employee at the facility, a product handler, had removed and improperly disposed of drums from the facility in September of 2001, without instructions from, or the knowledge of the management at this location. The product handler provided a written statement to the investigating authorities in which he admitted having disposed of the drums without instructions from anyone at the Company and that he knew that his actions were prohibited under law. The charges that have been filed against the Company carry potential fines of $50,000. The Company does not believe that it is criminally responsible for the actions of this former employee and intends to defend itself from these charges. The Company has begun discussions with the prosecuting authorities in an effort to resolve this matter.

In December 1999, the Company contributed certain pumping service equipment to a limited partnership. The equipment is used to provide services to the Company’s customers for which the Company pays a service fee over a period of at least six years, but not more than 13 years, at approximately $12 million annually. This is accounted for as an operating lease and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $33.9 million and $47.8 million as of September 30, 2003 and September 30, 2002, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. The Company received partnership approval in September 2003 to substitute certain pumping service equipment and has accounted for it as an exchange of like-kind assets with no earnings impact since the earnings process has not yet culminated. As a result of the substitutions, the deferred gain was reduced by $9.2 million as of September 30, 2003. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million.

accounted for as an operating lease and is included in “Obligations under equipment financing arrangements” in the Contractual Obligations section below. The Company owns a 1% interest in the limited partnership. The transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $16.0 and $18.8 million as of September 30, 2003 and September 30, 2002, respectively. The agreement permits substitution of equipment within the partnership as long as the implied fair value of the new property transferred in at the date of substitution equals or exceeds the implied fair value, as defined, of the current property in the partnership that is being replaced. The Company received partnership approval in October 2003 to substitute certain pumping service equipment and has accounted for it as an exchange of like-kind assets with no earnings impact since the earnings process has not yet culminated. As a result of the substitutions, the deferred gain was reduced by $14.1 million subsequent to September 30, 2003. In June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million.

At September 30, 2003, the Company had long-term operating leases and service fee commitments covering certain facilities and equipment, as well as other long-term commitments, with varying expiration dates. Minimum annual commitments for the years ended September 30, 2004, 2005, 2006, 2007 and 2008 are $62.4 million, $60.0 million, $56.0 million, $44.4 million and $35.2 million, respectively and $76.9 million in the aggregate thereafter.

The Company routinely issues Parent Company Guarantees (“PCG’s) in connection with service contracts entered into by the Company’s subsidiaries. The issuance of these PCG’s is frequently a condition of the bidding process imposed by the Company’s customers for work in countries outside of North America. The PCG’s typically provide that the Company guarantees the performance of the services by the Company’s local subsidiary. The term of these PCG’s varies with length of the services contract.

The Company arranges for the issuance of a variety of bank guarantees, performance bonds and standby letters of credit. The vast majority of these are issued in connection with contracts the Company, or a subsidiary, has entered into with its customers. The customer has the right to call on the bank guarantee, performance bond or standby letter of credit in the event that the Company, or the subsidiary, defaults in the performance of the services. These instruments are required as a condition to the Company, or the subsidiary, being awarded the contract, and are typically released upon completion of the contract. The balance of these instruments are predominantly standby letters of credit issued in connection with a variety of the Company’s financial obligations, such as in support of fronted insurance programs, claims administration funding, certain employee benefit plans and temporary importation bonds. The following table summarizes the Company’s other commercial commitments as of September 30, 2003 (in thousands):

The following table summarizes the Company’s contractual cash obligations and other commercial commitments as of September 30, 2003 (in thousands):

The Company conducts some of its operations through investments in affiliates that are accounted for using the cost or equity method.

PD Mexicana Sociedad de Responsabilidad Limitada de Capital Variable (“PDM”) – PDM was incorporated in January 2001. Its main activity is to provide drilling and integrated services to wells in development stage by means of a contract established with Pemex Exploracions y Produccion (“Pemex”). The sole purpose of PDM is to carry out and complete the Pemex contract, which expires in August 2005. BJ Service International, Inc. (a wholly owned subsidiary of the Company) and PD Holdings (a wholly owned subsidiary of Precision Drilling Corporation) each own 50% of PDM. Funding for PDM expenses is made on a basis consistent with the ownership percentages.

Societe Algerienne de Stimulation de Puits Producteurs d’Hydroncarbures (“BJSP”) – the purpose of BJSP is to perform services such as casing, cementing, stimulation and well testing in Algeria. BJ Service International, Inc. (a wholly owned subsidiary of the Company) owns 49% of BJSP and L’Enterprise de Services aux Puits owns the remaining 51%. The current agreemement expires in July 2005 and can be extended by mutual agreement of the stockholders. Profits and losses are shared by the stockholders in proportion to their ownership percentages.

Societe de Services Industriels (“SSI”) – BJ Services International Sarl (a wholly owned subsidiary of the Company) owns 50% of SSI and L’Air Liquide S.A. owns the remaining 50%. The stockholders share the profits and losses of SSI in proportion to their ownership percentages.

At September 30, 2003 and 2002, combined net accounts receivable reflected in our Consolidated Statement of Financial Position from unconsolidated affiliates totaled $14.3 million and $13.8 million, respectively. At September 30, 2003 and 2002, combined accounts payable reflected in our Consolidated Statement of Financial Position from unconsolidated affiliates totaled $0.2 million and $0.1 million, respectively. The Company’s combined investment on September 30, 2003 and 2002 was $13.5 million and $12.4 million, respectively. The Company recognized revenue of $35.9 million, $34.8 million, and $18.0 million for the years ending September 30, 2003, 2002, and 2001, respectively, primarily for services performed on behalf of its equity affiliates.

Supplemental financial information for the three years ended September 30, 2003 is as follows (in thousands):

Other (expense) income, net for the three years ended September 30, 2003 is summarized as follows (in thousands):

Accumulated other comprehensive income (loss) consists of the following (in thousands):

The tax effects allocated to each component of other comprehensive income is summarized as follows (in thousands):

Stock Option Plans: The Company’s 1990 Stock Incentive Plan, 1995 Incentive Plan, 1997 Incentive Plan, and 2000 Incentive Plan (the “Plans”) provide for the granting of options for the purchase of the Company’s common stock (“Common Stock”) and other performance based awards to officers, key employees and nonemployee directors. Options vest over three or four-year periods and are exercisable for periods ranging from one to ten years. An aggregate of 23,962,454 shares of Common Stock has been reserved for grants, of which 4,792,051 were available for future grants at September 30, 2003.

A summary of the status of the Company’s stock option activity and related information for each of the three years ended September 30, 2003 is presented below (in thousands, except per share prices):

The following table summarizes information about stock options outstanding as of September 30, 2003 (in thousands, except per share prices and remaining life):

Stock Purchase Plan: The Company’s 1990 Employee Stock Purchase Plan and 1999 Employee Stock Purchase Plan (together, the “Purchase Plan”) allow all employees to purchase shares of the Company’s Common Stock at 85% of market value on the first or last business day of the twelve-month plan period beginning each October, whichever is lower. Purchases are limited to 10% of an employee’s regular pay. A maximum aggregate of 8,558,124 shares has been reserved under the Purchase Plan, 4,704,075 of which were available for future purchase at September 30, 2003. In October 2003, 494,982 shares were purchased at $22.10 and in October 2002, 661,215 shares were purchased at $15.12 per share.

SFAS No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation”, encourages, but does not require, companies to record compensation cost for employee stock-based compensation plans at fair value as determined by generally recognized option pricing models such as the Black-Scholes model or a binomial model. Because of the inexact and subjective nature of deriving stock option values using these methods, the Company has adopted the disclosure-only provisions of SFAS 123 and continues to account for the Stock Option Plan and the Stock Purchase Plan as it has in the past using the intrinsic value method prescribed in Accounting Principles Board (“APB”) 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation expense has been recognized in the consolidated statement of operations for the Company’s employee stock option plans. In December 2002, SFAS No.148, “Accounting for Stock-Based Compensation-Transition and Disclosure” was issued, which amended SFAS 123. This statement revises the disclosure provisions on an annual and interim basis to show the effect on reported results if the Company had applied the fair value recognition provisions of SFAS 123. The Company adopted these provisions as reflected in Note 2.

Stock Incentive Plan: Pursuant to the terms of the 1990 Stock Incentive Plan and 1997 Stock Incentive Plan, from 1993 through 2000 the Company granted a total of 1,767,814 Performance Units (“Units”) to its officers. Each Unit represents the right to receive from the Company at the end of a stipulated period one unrestricted share of Common Stock, contingent upon achievement of certain financial performance goals over the stipulated period. Should the Company fail to achieve the specific financial goals as set by the Executive Compensation Committee of the Board of Directors, the Units are canceled and the related shares revert to the Company for reissuance under the plan. The aggregate fair market value of the underlying shares granted under this plan is considered unearned compensation at the time of grant and is adjusted quarterly based on the current market price for the Common Stock. Compensation expense is determined based on management’s current estimate of the likelihood of meeting the specific financial goals and expensed ratably over the stipulated period. Between April 1995 and November 2000, a total of 1,061,730 Units were converted into Common Stock and issued to officers, 50,990 Units were deferred for later issuance and 371,192 Units were canceled. All of the 50,990 deferred Units were converted into Common Stock as of September 30, 2002. In June 2002, 41,771 shares

were forfeited upon the retirement or resignation of former officers. On November 21, 2002, the Executive Compensation Committee of the Board of Directors reviewed the Company’s performance for the three-year period ending September 30, 2002 and determined that the highest level of performance criteria was achieved for the Unit awards made in December 1999. Therefore, a total of 146,595 Units were converted into stock and issued to officers. In 2003, an additional 412 shares were forfeited upon the retirement of a former officer. On November 20, 2003, the Executive Compensation Committee of the Board of Directors reviewed the Company’s performance for the three-year period ending September 30, 2003 and determined that the highest level of performance criteria was achieved for the Unit awards made in November 2000. Therefore, a total of 95,126 Units were converted into stock and issued to officers.

Stockholder Rights Plan: The Company has a Stockholder Rights Plan (the “Rights Plan”) designed to deter coercive takeover tactics and to prevent an acquirer from gaining control of the Company without offering a fair price to all of its stockholders. Under this plan, as amended, each outstanding share of Common Stock includes one-quarter of a preferred share purchase right (“Right”) that becomes exercisable under certain circumstances, including when beneficial ownership of the Common Stock by any person, or group, equals or exceeds 15% of the Company’s outstanding Common Stock. Each Right entitles the registered holder to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock at a price of $520, subject to adjustment under certain circumstances. As a result of stock splits effected in the form of stock dividends in 1998 and 2001, one Right is associated with four outstanding shares of Common Stock. The purchase price for the one-fourth of a Right associated with one share of Common Stock is effectively $130. Upon the occurrence of certain events specified in the Rights Plan, each holder of a Right (other than an Acquiring Person) will have the right, upon exercise of such Right, to receive that number of shares of Common Stock of the Company (or the surviving corporation) that, at the time of such transaction, would have a market price of two times the purchase price of the Right. The Rights Plan was amended September 26, 2002, to extend the expiration date of the Rights to September 26, 2012 and increase the purchase price of the Rights. No shares of Series A Junior Participating Preferred Stock have been issued by the Company at September 30, 2003.

Stock Split: At a special meeting on May 10, 2001, the Company’s stockholders approved an amendment to the Company’s charter increasing the number of authorized shares of Common Stock from 160 million to 380 million shares. This allowed the Company to effect a 2 for 1 stock split (in the form of a dividend) previously authorized by the Board of Directors on March 22, 2001. The distribution on May 31,2001 increased the number of shares outstanding from 82,283,861 to 164,567,722. All share and per share data, including stock option and stock purchase plan information have been restated to reflect the stock split.

Treasury Stock: In December 1997, the Board of Directors approved a share repurchase program authorizing purchases of up to $150 million of Common Stock at the discretion of the Company’s management. The Board subsequently increased the authorized amount to $300 million in May 1998, to $450 million in September 2000, to $600 million in July 2001 and again to $750 million in October 2001. Under this program, the Company repurchased 19,807,000 shares at a cost of $396.9 million through fiscal 2001 and 4,376,000 shares at a cost of $102.1 million during fiscal 2002.

Convertible Senior Notes: On April 24, 2002, the Company sold convertible senior notes with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). See Note 5.

On December 2, 2003, the Company acquired the assets and business of Petro-Drive, a division of Grant Prideco, Inc., for a total purchase price of $7 million. Petro-Drive, located in Lafayette, Louisiana, is a leading provider of Hydraulic and diesel hammer services to the Gulf of Mexico market and select markets internationally. This acquisition was accounted for using the purchase method of accounting.

The Board of Directors approved the 2003 Incentive Plan which permits the granting of stock options, stock based awards and cash awards to employees, officers and non-employee directors. An aggregate of up to 4,000,000 shares of Common Stock may be issued under the 2003 Incentive Plan.

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Information concerning the directors of the Company is set forth in the section entitled “Election of Directors” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which section is incorporated herein by reference. For information regarding executive officers of the Company, see page 14 hereof. Information concerning compliance with Section 16(a) of the Exchange Act is set forth in the section entitled “Compliance with Section 16(a) of the Exchange Act” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which section is incorporated herein by reference.

Information concerning the Audit Committee of the Company and the audit committee financial expert is set forth in the section entitled “Board of Directors and Committees of the Board” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which section is incorporated herein by reference. Information concerning the Company’s Code of Ethics is set forth in the section entitled “Code of Ethics” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which section is incorporated herein by reference.

Information for this item is set forth in the sections entitled “Election of Directors,” “Executive Compensation” and “Severance Agreements” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which sections are incorporated herein by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related

Information for this item is set forth in the sections entitled “Voting Securities” and “Election of Directors” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which sections are incorporated herein by reference.

Information for this item is set forth in the sections entitled “Certain Relationships and Related Party Transactions” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which sections are incorporated herein by reference.

Information for this item is set forth in the section entitled “Independent Auditors” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 22, 2004, which sections are incorporated herein by reference.

ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

The following financial statements of the Registrant as set forth under Part II, Item 8 of this report on Form 10-K on the pages indicated.

All other financial statement schedules are omitted because of the absence of conditions under which they are required or because all material information required to be reported is included in the consolidated financial statements and notes thereto.

On July 22, 2003, the Company furnished a Form 8-K attaching a press release with respect to an announcement of the financial results for the third quarter ended June 30, 2003, pursuant to Item 12 of Form 8-K.

On November 4, 2003, the Company furnished a Form 8-K attaching a press release with respect to an announcement of the financial results for the fourth quarter ended September 30, 2003, pursuant to Item 12 of Form 8-K.

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

BJ SERVICES COMPANY

By		/s/ J.W. STEWART
		J. W. Stewart President and Chief Executive Officer

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

Delaware		63-0084140
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5500 Northwest Central Drive, Houston, Texas		77092
(Address of principal executive offices)		(Zip Code)

Title of each class		Name of each exchange on which registered
Common Stock $.10 par value per share		New York Stock Exchange
Preferred Share Purchase Rights		New York Stock Exchange
7% Series B Notes due 2006		New York Stock Exchange

		Page
PART I
Item 1.	Business	3
Item 2.	Properties	15
Item 3.	Legal Proceedings	16
Item 4.	Submission of Matters to a Vote of Security Holders	18

PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	19
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
Item 9A.	Controls and Procedures	73

PART III
Item 10.	Directors and Executive Officers of the Registrant	73
Item 11.	Executive Compensation	73
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	73
Item 13.	Certain Relationships and Related Transactions	73
Item 14.	Principal Accountant Fees and Services	73

PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	74

	Common Stock Price Range
	High		Low
Fiscal 2002
1st Quarter	$	34.05	$	16.85
2nd Quarter		35.90		25.30
3rd Quarter		39.49		31.75
4th Quarter		35.19		23.00
Fiscal 2003
1st Quarter		35.45		24.31
2nd Quarter		36.23		29.25
3rd Quarter		42.40		33.80
4th Quarter		39.19		32.51
Fiscal 2004
1st Quarter (through December 5, 2003)		36.43		30.11

	As of and For the Year Ended September 30,
	2003			2002(1)(3)			2001			2000(2)			1999
	(in thousands, except per share amounts)
Operating Data:
Revenue	$	2,142,877		$	1,865,796		$	2,233,520		$	1,555,389		$	1,131,334
Operating expenses, excluding goodwill amortization		1,849,636			1,602,906			1,683,602			1,348,118			1,132,721	(4)
Goodwill amortization		—			—			13,739			13,497			13,525
Operating income (loss)		293,241			262,890			536,179			193,774			(14,912	)
Interest expense		(15,948	)		(8,979	)		(13,282	)		(19,968	)		(31,365	)
Interest income		2,141			2,008			2,567			1,576			608
Other income (expense), net		(3,762	)		(3,225	)		3,717			(99	)		760
Income tax expense (benefit)		87,495			86,199			179,922			57,307			(15,221	)
Net income (loss)		188,177			166,495			349,259			117,976			(29,688	)
Earnings (loss) per share(5):
Basic		1.19			1.06			2.13			.74			(.21	)
Diluted		1.17			1.04			2.09			.70			(.21	)
Depreciation and amortization		120,213			104,915			104,969			102,018			99,800
Capital expenditures(6)		167,183			179,007			183,414			80,518			110,566

Financial Position Data (at end of period):
Property, net	$	850,340		$	798,956		$	676,445		$	585,394		$	659,717
Total assets		2,785,957			2,442,370			1,985,367			1,785,233			1,824,764
Long-term obligations, excluding current maturities		493,754			489,062			79,393			141,981			422,764
Stockholders’ equity		1,650,632			1,418,628			1,370,081			1,169,771			877,089

Name	Age	Position with the Company	Office Held Since
J. W. Stewart	59	Chairman of the Board, President and Chief Executive Officer	1990
Mark Airola	45	Assistant General Counsel and Chief Compliance Officer	2003
Susan Douget	43	Director of Human Resources	2003
David Dunlap	42	Vice President and President – International Division	1995
Mark Hoel	45	Vice President—Technology and Logistics	2002
Brian McCole	44	Controller	2002
Margaret B. Shannon	54	Vice President—General Counsel	1994
Jeffrey E. Smith	41	Treasurer	2002
T. M. Whichard	45	Vice President—Finance and Chief Financial Officer	2002
Kenneth A. Williams	53	Vice President and President – U.S. Division	1991

	2003			2002			2001
Rig Count: (1)
U.S.		966			870			1,172
International (2)		1,102			995			1,100
Consolidated revenue (in millions)	$	2,142.9		$	1,865.8		$	2,233.5
Revenue by business segment (in millions):
U.S./Mexico Pressure Pumping	$	982.6		$	898.7		$	1,219.4
International Pressure Pumping		801.8			712.6			794.7
Other Oilfield Services		358.5			253.7			219.0
Corporate		—			.8			.5
Percentage of research and engineering expense to revenue		1.9	%		2.0	%		1.5	%
Percentage of marketing expense to revenue		3.4	%		3.4	%		2.8	%
Percentage of general and administrative expense to revenue		3.2	%		3.6	%		3.0	%
Consolidated operating income (in millions)	$	293.2		$	262.9		$	549.9
Operating income by business segment (in millions): (3)
U.S./Mexico Pressure Pumping	$	190.3		$	189.1		$	425.1
International Pressure Pumping		90.7			72.1			126.8
Other Oilfield Services		49.9			30.2			34.4
Corporate		(37.7	)		(28.5	)		(36.4	)

			Payments Due by Period
Contractual Cash Obligations	Total		Less than 1 year		1-3 Years		4-5 Years		After 5 Years
Long term debt	$	493,754	$	—	$	78,888	$	—	$	414,866
Capital lease obligations		—		—		—		—		—
Operating leases		335		62		116		80		77
Obligations under equipment financing arrangements		165,580		22,590		47,710		47,614		47,666
Purchase obligations		—		—		—		—		—
Other long-term liabilities		14,303		542		1,084		1,084		11,593

Total contractual cash obligations	$	673,972	$	23,194	$	127,798	$	48,778	$	474,202

Other Commercial Commitments	Total Amounts Committed		Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby letters of credit	$	26,395	$	26,347	$	—	$	—	$	48
Guarantees		159,586		122,369		23,210		3,478		10,529

Total commercial commitments	$	185,981	$	148,716	$	23,210	$	3,478	$	10,577

	Expected Maturity Dates							Thereafter		Total		Fair Value September 30, 2003
	2004		2005	2006		2007	2008	Thereafter		Total		Fair Value September 30, 2003
SHORT-TERM BORROWINGS
Bank borrowings; U.S. $ denominated	$	5,888								$	5,888	$	5,888
Average variable interest rate – 5.00% at September 30, 2003
LONG-TERM BORROWINGS
7% Series B Notes – U.S. $ denominated
Fixed interest rate –7%				$	78,888						78,888		86,537
1.625% Convertible Notes U.S. denominated
Fixed interest rate – 1.625%								$	414,866		414,866		421,961
FINANCIAL INSTRUMENTS
Forward foreign exchange contracts	$	42									42		42

Total	$	5,930	—	$	78,888	—	—	$	414,866	$	499,684	$	514,428

	Year Ended September 30,
	2003			2002			2001
	(in thousands, except per share amounts)
Revenue	$	2,142,877		$	1,865,796		$	2,233,520
Operating Expenses:
Cost of sales and services		1,665,545			1,435,540			1,519,722
Research and engineering		40,810			36,475			34,268
Marketing		73,665			64,095			63,266
General and administrative		69,449			66,627			66,305
Goodwill amortization		—			—			13,739
Loss on disposal of assets		167			169			41

Total operating expenses		1,849,636			1,602,906			1,697,341

Operating income		293,241			262,890			536,179
Interest expense		(15,948	)		(8,979	)		(13,282	)
Interest income		2,141			2,008			2,567
Other (expense) income, net		(3,762	)		(3,225	)		3,717

Income before income taxes		275,672			252,694			529,181
Income tax expense		87,495			86,199			179,922

Net income	$	188,177		$	166,495		$	349,259

Earnings Per Share:
Basic	$	1.19		$	1.06		$	2.13
Diluted	$	1.17		$	1.04		$	2.09
Weighted-Average Shares Outstanding:
Basic		157,943			156,981			163,885
Diluted		161,257			160,736			167,080

	September 30,
	2003		2002
	(in thousands)
Current Assets:
Cash and cash equivalents	$	277,666	$	84,727
Receivables, less allowance for doubtful accounts:
2003, $8,828; 2002, $14,097		469,656		364,214
Inventories:
Products		109,383		95,540
Work-in-process		2,048		1,971
Parts		51,137		62,339

Total inventories		162,568		159,850
Deferred income taxes		718		10,083
Prepaid expenses		20,606		23,079
Other current assets		10,494		6,838

Total current assets		941,708		648,791
Property:
Land		14,806		14,206
Buildings and other		238,835		211,643
Machinery and equipment		1,327,451		1,188,105

Total property		1,581,092		1,413,954
Less accumulated depreciation		730,752		614,998

Property, net		850,340		798,956
Goodwill		879,710		872,959
Deferred income taxes		66,877		73,768
Investments and other assets		47,322		47,896

Total assets	$	2,785,957	$	2,442,370

	Common Stock Shares		Common Stock		Capital In Excess Of Par			Treasury Stock			Unearned Compensation			Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance, September 30, 2000	83,048		$	8,688	$	948,859		$	(165,154	)	$	(3,433	)	$	376,270		$	4,541		$	1,169,771
Comprehensive income:
Net income															349,259
Other comprehensive income, net of tax:
Cumulative translation adjustments																		(2,180	)
Minimum pension liability adjustment																		(5,994	)
Comprehensive income																					341,085
Reissuance of treasury stock for:
Stock options	921					(589	)		37,454						(23,986	)					12,879
Stock purchase plan	196								8,052						(2,727	)					5,325
Stock performance plan	34					(1,397	)		1,397
Stock split	82,280			8,688											(8,688	)
Acquisition	6					171			267												438
Treasury stock purchased	(6,001	)							(177,465	)											(177,465	)
Recognition of unearned compensation												3,165									3,165
Stock performance award						4,141						(4,141	)
Revaluation of stock performance awards						482						(482	)
Tax benefit from exercise of options						14,883															14,883

Balance, September 30, 2001	160,484		$	17,376	$	966,550		$	(295,449	)	$	(4,891	)	$	690,128		$	(3,633	)	$	1,370,081
Comprehensive income:
Net income															166,495
Other comprehensive income, net of tax:
Cumulative translation adjustments																		(4,655	)
Minimum pension liability adjustment																		(21,585	)
Comprehensive income																					140,255
Reissuance of treasury stock for:
Stock options	440								9,884						(6,062	)					3,822
Stock purchase plan	243								5,330						(1,660	)					3,670
Stock performance plan	5								114						(114	)
Cancellation of stock issued for acquisition	(1	)							(25	)					(15	)					(40	)
Treasury stock purchased	(4,376	)							(102,125	)											(102,125	)
Recognition of unearned compensation												983									983
Revaluation of stock performance awards						(2,982	)					2,982
Tax benefit from exercise of options						1,982															1,982

Balance, September 30, 2002	156,795		$	17,376	$	965,550		$	(382,271	)	$	(926	)	$	848,772		$	(29,873	)	$	1,418,628
Comprehensive income:
Net income															188,177
Other comprehensive income, net of tax:
Cumulative translation adjustments																		21,456
Minimum pension liability adjustment																		(1,230	)
Comprehensive income																					208,403
Reissuance of treasury stock for:
Stock options	705								15,828						(5,732	)					10,096
Stock purchase plan	659								14,862						(4,892	)					9,970
Stock performance plan	147					(3,812	)		3,304						507						(1	)
Recognition of unearned compensation												1,108									1,108
Revaluation of stock performance awards						182						(182	)
Tax benefit from exercise of options						2,428															2,428

Balance, September 30, 2003	158,306		$	17,376	$	964,348		$	(348,277	)	$	—		$	1,026,832		$	(9,647	)	$	1,650,632

	U.S./Mexico Pumping Services			Int’l Pumping Services		BJ Chemical Services		PPS		Casing and Tubular		Completion Tools		Completion Fluids		Ending Balance
Balance as of 10/1/01	$	188,543		$	246,349	$	10,726	$	22,272	$	8,905	$	—	$	—	$	476,795
Goodwill acquired during year (see Note 3)		85,766			124,919		—		—		—		107,907		77,572		396,164

Balance as of 09/30/02	$	274,309		$	371,268	$	10,726	$	22,272	$	8,905	$	107,907	$	77,572	$	872,959

Purchase price adjustments		(251	)		56		—		—		—		4,328		2,618		6,751

Balance as of 09/30/03	$	274,058		$	371,324	$	10,726	$	22,272	$	8,905	$	112,235	$	80,190	$	879,710

	For the Year Ended September 30, 2001
Reported net income	$	349,259
Add back: Goodwill amortization		13,739

Adjusted net income	$	362,998

Basic earnings per share:
Reported net income	$	2.13
Goodwill amortization		.08

Adjusted net income	$	2.21

Diluted earnings per share:
Reported net income	$	2.09
Goodwill amortization		.08

Adjusted net income	$	2.17

	Allocation as of September 30, 2002			Adjustments		Allocation as of September 30, 2003
Consideration paid:
Cash to OSCA stockholders	$	416,252				$	416,252
Settlement of options		8,197					8,197
Debt assumed		35,000					35,000
Transaction costs		11,124					11,124

Total consideration	$	470,573				$	470,573
Allocation of consideration paid:
Cash and cash equivalents	$	5,073				$	5,073
Accounts receivable		24,588					24,588
Inventory		25,767		316			26,083
Prepaid expenses		879					879
Current deferred income taxes		4,031					4,031
Property, plant and equipment		49,424		1,140			50,564
Other assets		8,785					8,785
Short-term debt		(440	)				(440	)
Accounts payable		(25,582	)	(34	)		(25,616	)
Other accrued liabilities		(21,295	)	(2,010	)		(23,305	)
Accrued income and other taxes(1)		7,416		(6,144	)		1,272

Goodwill	$	391,927				$	398,659

	2003		2002
Convertible Senior Notes due 2022, net of discount	$	414,866	$	410,223
7% Series B Notes due 2006, net of discount		78,888		78,839
Other				256

		493,754		489,318
Less current maturities of long-term debt				256

Long-term debt	$	493,754	$	489,062

	2003				2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7% Series B Notes	$	78,888	$	86,537	$	78,839	$	86,410
Convertible Senior Notes due 2022		414,866		421,961		410,223		403,238
Forward Foreign Exchange Contracts		42		42		—		—

	2003			2002
Assets:
Expenses accrued for financial reporting purposes, not yet deducted for tax	$	74,250		$	89,417
Alternative minimum tax credit carryforward		14,498
Net operating loss carryforwards		10,144			42,620
Valuation allowance		(10,144	)		(39,140	)

Total deferred tax asset	$	88,748		$	92,897

Liabilities:
Differences in depreciable basis of property	$	(26,032	)		(15,977	)
Income accrued for financial reporting purposes, not yet reported for tax		(2,596	)		(2,282	)

Total deferred tax liability		(28,628	)		(18,259	)

Net deferred tax asset (liability)	$	60,120		$	74,638

	U.S./Mexico Pressure Pumping		International Pressure Pumping		Other Oilfield Services		Corporate			Total
2003
Revenue	$	982,630	$	801,746	$	358,479	$	22		$	2,142,877
Operating income (loss)		190,301		90,662		49,950		(37,672	)		293,241
Identifiable assets		832,736		1,044,811		482,193		426,217			2,785,957
Capital expenditures		72,827		60,380		19,557		14,419			167,183
Depreciation		44,491		55,110		16,132		4,480			120,213

2002
Revenue(2)	$	898,691	$	712,612	$	253,665	$	828		$	1,865,796
Operating income (loss)		189,136		72,068		30,220		(28,534	)		262,890
Identifiable assets		764,029		989,174		463,610		225,557			2,442,370
Capital expenditures		75,141		77,702		16,713		9,451			179,007
Depreciation		36,046		51,485		13,572		3,812			104,915

2001
Revenue	$	1,219,356	$	794,687	$	218,987	$	490		$	2,233,520
Operating income (loss)(1)		425,051		126,828		34,408		(36,369	)		549,918
Identifiable assets		717,593		850,856		180,088		236,830			1,985,367
Capital expenditures		116,703		51,999		13,087		1,625			183,414
Depreciation and amortization		24,449		49,694		11,228		19,598			104,969

	Revenue		Long-Lived Assets
2003
United States	$	1,068,465	$	1,322,962
Canada		253,851		111,618
Other countries		820,561		342,792

Consolidated total	$	2,142,877	$	1,777,372

2002
United States	$	968,520	$	1,295,639
Canada		200,020		99,364
Other countries		697,256		327,633

Consolidated total	$	1,865,796	$	1,722,636

2001
United States	$	1,274,806	$	794,292
Canada		260,608		100,362
Other countries		698,106		278,554

Consolidated total	$	2,233,520	$	1,173,208

	2003			2002
Vested benefit obligation	$	66,834		$	61,762

Projected benefit obligation	$	66,834		$	61,762
Plan assets at fair value		48,197			43,984

Projected benefit obligation in excess of plan assets		18,637			17,778
Cumulative unrecognized loss		(23,322	)		(23,186	)
Adjustment required to recognize minimum liability		23,322			23,186

Net pension liability	$	18,637		$	17,778

	2003			2002
Change in benefit obligation
Defined benefit plan obligation, beginning of year	$	61,762		$	58,233
Interest cost		3,902			3,886
Actuarial loss		4,445			2,762
Benefits paid from plan assets		(3,275	)		(3,119	)

Defined benefit plan obligation, end of year	$	66,834		$	61,762


	2003			2002
Change in plan assets
Fair value of plan assets, beginning of year	$	43,984		$	51,200
Company contributions
Actual (loss)gain on plan assets		7,488			(4,097	)
Benefits paid from plan assets		(3,275	)		(3,119	)

Fair value of plan assets, end of year	$	48,197		$	43,984

	2003			2002
Actuarial present value of:
Vested benefit obligation	$	84,259		$	65,278

Accumulated benefit obligation	$	84,344		$	65,471

Projected benefit obligation	$	91,381		$	73,366
Plan assets at fair value		63,189			45,930

Projected benefit obligation in excess of plan assets		28,192			27,436
Unrecognized loss		(31,173	)		(27,987	)
Unrecognized transition asset, net of amortization		12			14
Unrecognized prior service cost		(71	)		(91	)
Adjustment required to recognize minimum liability		22,894			21,270

Net pension liability	$	19,854		$	20,642

	2003			2002
Accumulated postretirement benefit obligation:
Retirees	$	5,265		$	5,281
Fully eligible active plan participants		7,282			5,414
Other active plan participants		28,284			23,275

		40,831			33,970
Unrecognized cumulative net gain (loss)		(2,534	)		193

Accrued postretirement benefit liability	$	38,297		$	34,163

	Minimum Pension Liability Adjustment			Cumulative Translation Adjustment			Total
Balance, October 1, 2000	$	(2,381	)	$	6,922		$	4,541
Changes		(5,994	)		(2,180	)		(8,174	)

Balance, September 30, 2001	$	(8,375	)	$	4,742		$	(3,633	)
Changes		(21,585	)		(4,655	)		(26,240	)

Balance, September 30, 2002	$	(29,960	)	$	87		$	(29,873	)
Changes		(1,230	)		21,456			20,226

Balance, September 30, 2003	$	(31,190	)	$	21,543		$	(9,647	)

	Before-tax Amount			Tax (expense) Benefit		Net-of-tax Amount
Year Ended September 30, 2001:
Foreign currency translation adjustment	$	(2,180	)			$	(2,180	)
Minimum pension liability adjustment		(9,222	)	$	3,228		(5,994	)

Other comprehensive income	$	(11,402	)	$	3,228	$	(8,174	)

Year Ended September 30, 2002:
Foreign currency translation adjustment	$	(4,655	)			$	(4,655	)
Minimum pension liability adjustment		(31,571	)	$	9,986		(21,585	)

Other comprehensive income	$	(36,226	)	$	9,986	$	(26,240	)

Year Ended September 30, 2003:
Foreign currency translation adjustment	$	21,456				$	21,456
Minimum pension liability adjustment		(1,767	)	$	537		(1,230	)

Other comprehensive income	$	19,689		$	537	$	20,226

	Options Outstanding				Options Exercisable
Range of Exercise Price	Shares	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price		Shares	Weighted-Average Exercise Price
$ 5.40 – 8.10	1,600	4.8	$	7.05	1,600	$	7.05
8.15 – 12.15	126	3.4		11.39	126		11.39
12.16 – 18.23	348	4.6		17.32	341		17.30
18.24 – 27.34	3,225	5.0		21.73	1,127		21.92
27.35 – 37.05	1,495	4.6		31.25	717		30.64

	6,794	4.8		19.95	3,911		16.69

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Fiscal Year Total
	(in thousands, except per share amounts)
Fiscal Year 2003:
Revenue	$	473,124	$	534,580	$	546,576	$	588,597	$	2,142,877
Gross profit (1)		88,077		109,184		112,760		126,501		436,522
Net income		33,470		44,808		49,544		60,355		188,177
Earnings per share:
Basic		.21		.28		.31		.38		1.19
Diluted		.21		.28		.31		.37		1.17

Fiscal Year 2002(2):
Revenue	$	510,061	$	442,388	$	439,646	$	473,701	$	1,865,796
Gross profit (1)		136,884		91,372		77,777		87,748		393,781
Net income		66,941		38,954		27,689		32,911		166,495
Earnings per share:
Basic		.42		.25		.18		.21		1.06
Diluted		.42		.24		.17		.21		1.04

		Page in this Form 10-K
Report of Independent Auditors		37
Consolidated Statement of Operations for the years ended September 30, 2003, 2002 and 2001		38
Consolidated Statement of Financial Position as of September 30, 2003 and 2002		39
Consolidated Statement of Stockholders’ Equity for the years ended September 30, 2003, 2002 and 2001		41
Consolidated Statement of Cash Flows for the years ended September 30, 2003, 2002 and 2001		42
Notes to Consolidated Financial Statements		43

Exhibit Number		Description of Exhibit

2.1		Agreement and Plan of Merger dated as of November 17, 1994 (“Merger Agreement”), among BJ Services Company, WCNA Acquisition Corp. and The Western Company of North America (filed as Exhibit 2.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1995, and incorporated herein by reference).

2.2		First Amendment to Agreement and Plan of Merger dated March 7, 1995, among BJ Services Company, WCNA Acquisition Corp. and The Western Company of North America (filed as Exhibit 2.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1995, and incorporated herein by reference).

2.3		Agreement and Plan of Merger dated as of February 20, 2002, among BJ Services Company, BJTX, Co., and OSCA, Inc. (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K dated May 31, 2002 and incorporated herein by reference).

3.1		Certificate of Incorporation, as amended as of April 13, 1995 (filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 and incorporated herein by reference).

Exhibit Number		Description of Exhibit

3.2		Certificate of Amendment to Certificate of Incorporation, dated January 22, 1998 (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 and incorporated herein by reference).

3.3		Certificate of Amendment to Certificate of Incorporation, dated May 10, 2001 (filed as Exhibit 3.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001 and incorporated herein by reference).

3.4		Certificate of Designation of Series A Junior Participating Preferred Stock, as amended (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1996 and incorporated herein by reference).

3.5		Amended and Restated Bylaws, as of March 28, 2002 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated May 31, 2002, and incorporated herein by reference).

*3.6		Amended and Restated Bylaws, as of December 4, 2003.

4.1		Specimen form of certificate for the Common Stock (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1 (Reg. No. 33-35187) and incorporated herein by reference).

4.2		Amended and Restated Rights Agreement dated September 26, 1996, between the Company and First Chicago Trust Company of New York, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-K dated October 21, 1996 and incorporated herein by reference).

4.3		First Amendment to Amended and Restated Rights Agreement and Appointment of Rights Agent, dated March 31, 1997, among the Company, First Chicago Trust Company of New York and The Bank of New York (filed as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 and incorporated herein by reference).

4.4		Second Amendment to Amended and Restated Rights Agreement dated as of September 26, 2002, between the Company and The Bank of New York (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K dated September 26, 2002 and incorporated herein by reference).

4.5		Indenture among the Company, BJ Services Company, U.S.A., BJ Services Company Middle East, BJ Service International, Inc. and Bank of Montreal Trust Company, Trustee, dated as of February 1, 1996, which includes the form of 7% Notes due 2006 and Exhibits thereto (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4 (Reg. No. 333-02287) and incorporated herein by reference).

4.6		First Supplemental Indenture, dated as of July 24, 2001, among the Company, BJ Services Company, U.S.A., BJ Services Company Middle East, BJ Service International, Inc. and The Bank of New York, as Trustee (filed as Exhibit 4.5 to the Company’s Form 8-A/A with respect to the Company’s preferred share purchase rights and incorporated herein by reference).

4.7		Amended and Restated Indenture effective as of April 24, 2002, between the Company and The Bank of New York, as Trustee, with respect to the Convertible Senior Notes due 2022 (filed as Exhibit 4.4 to the Company’s Registration Statement on Form S-3/A (Reg. No. 333-96981) and incorporated herein by reference).

10.1		Relationship Agreement dated as of July 20, 1990, between the Company and Baker Hughes Incorporated (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S-1 (Reg. No. 33-35187) and incorporated herein by reference).

10.2		Tax Allocation Agreement dated as of July 20, 1990, between the Company and Baker Hughes Incorporated (included as Exhibit A to Exhibit 10.1) (filed as Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (Reg. No. 33-35187) and incorporated herein by reference).

†10.3		1990 Stock Incentive Plan, as amended and restated (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (Reg. No. 33-62098) and incorporated herein by reference).

Exhibit Number		Description of Exhibit

†10.4		Amendment effective December 12, 1996, to 1990 Stock Incentive Plan, as amended and restated (filed as Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1996, and incorporated herein by reference).

†10.5		Amendment effective July 22, 1999 to 1990 Stock Incentive Plan (filed as Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999, and incorporated herein by reference).

†10.6		Amendment effective January 27, 2000 to 1990 Stock Incentive Plan (filed as Appendix A to the Company’s Proxy Statement dated December 20, 1999 and incorporated herein by reference).

†10.7		BJ Services Company 1995 Incentive Plan (filed as Exhibit 4.5 to the Company’s Registration Statement on Form S-8 (Reg. No. 33-58637) and incorporated herein by reference).

†10.8		Amendments effective January 25, 1996, and December 12, 1996, to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.9 to the Company’s Annual Report on form 10-K for the year ended September 30, 1996, and incorporated herein by reference).

†10.9		Amendment effective July 22, 1999 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999, and incorporated herein by reference).

†10.10		Amendment effective January 27, 2000 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated December 20, 1999 and incorporated herein by reference).

†10.11		Amendment effective May 10, 2001 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated April 10, 2001 and incorporated herein by reference).

†10.12		Eighth Amendment effective October 15, 2001 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

†10.13		1997 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated December 22, 1997 and incorporated herein by reference).

†10.14		Amendment effective July 22, 1999 to 1997 Incentive Plan (filed as Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999, and incorporated herein by reference).

†10.15		Amendment effective January 27, 2000 to 1997 Incentive Plan (filed as Appendix C to the Company’s Proxy Statement dated December 20, 1999 and incorporated herein by reference).

†10.16		Amendment effective May 10, 2001 to 1997 Incentive Plan (filed as Appendix C to the Company’s Proxy Statement dated April 10, 2001 and incorporated herein by reference).

†10.17		Fifth Amendment effective October 15, 2001 to 1997 Incentive Plan (filed as Exhibit 10.17 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

†10.18		1999 Employee Stock Purchase Plan (filed as Appendix A to the Company’s Proxy Statement dated December 21, 1998 and incorporated herein by reference).

†10.19		Amendment effective September 23, 1999 to BJ Services Company 1999 Employee Stock Purchase Plan (filed as Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

†*10.20		Third Amendment effective September 1, 2001 to BJ Services Company 1999 Employee Stock Purchase Plan.

Exhibit Number		Description of Exhibit

†10.21		BJ Services Company 2000 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated December 20, 2000 and incorporated herein by reference).

†10.22		First Amendment effective March 22, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.2 to the Company’s Registration Statement on Form S-8 (Reg. No. 333-73348) and incorporated herein by reference).

†10.23		Second Amendment effective May 10, 2001 to BJ Services Company 2000 Incentive Plan (filed as Appendix D to the Company’s Proxy Statement dated April 10, 2001 and incorporated herein by reference).

†10.24		Third Amendment effective October 15, 2001 to BJ Services Company 2000 Incentive Plan (filed as Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

†10.25		BJ Services Supplemental Executive Retirement Plan effective October 1, 2000 (filed as Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2000 and incorporated herein by reference).

†10.26		Key Employee Security Option Plan (filed as Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 and incorporated herein by reference).

†10.27		Directors’ Benefit Plan, effective December 7, 2000 (filed as Exhibit 10.27 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

†10.28		BJ Services Deferred Compensation Plan, as amended and restated effective October 1, 2000 (filed as Exhibit 10.29 to the Company’s Form 10-Q for the quarter ended March 31, 2001 and incorporated herein by reference).

†10.29		Form of Amended and Restated Executive Severance Agreement between BJ Services Company and certain executive officers (filed as Exhibit 10.28 to the Company’s Form 10-Q for the quarter ended March 31, 2000 and incorporated herein by reference).

10.30		Credit Agreement, dated as of June 27, 2001 among the Company, the lenders from time to time party thereto, Royal Bank of Canada and The Bank of New York, as Co-Syndication Agents, The Royal Bank of Scotland plc and Bank One, N.A., as Co-Documentation Agents, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (filed as Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

10.31		Form of Revolving Loan Note and Swing Line Note pursuant to the Credit Agreement (filed as Exhibit 10.31 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

10.32		364-Day Credit Agreement, dated as of June 27, 2001 among the Company, the lenders from time to time party thereto, Royal Bank of Canada and The Bank of New York, as Co-Syndication Agents, The Royal Bank of Scotland plc and Bank One, N.A. as Co-Documentation Agents, and Bank of America, N.A., as Administrative Agent (filed as Exhibit 10.32 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

10.33		Form of Promissory Note pursuant to the 364-Day Credit Agreement (filed as Exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2001 and incorporated herein by reference).

10.34		Trust Indenture and Security Agreement dated as of August 7, 1997 among First Security Bank, National Association, BJ Services Equipment, L.P. and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 and incorporated herein by reference).

Exhibit Number		Description of Exhibit

10.35		Indenture Supplement No. 1 dated as of August 8, 1997 between First Security Bank, as Nonaffiliated Partner Trustee, and BJ Services Equipment, L.P., and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.17 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 and incorporated herein by reference).

10.36		Amended and Restated Agreement of Limited Partnership dated as of August 7, 1997 of BJ Services Equipment, L.P (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 and incorporated herein by reference).

10.37		Trust Indenture and Security Agreement dated as of December 15, 1999 among First Security Trust Company of Nevada, BJ Services Equipment II, L.P. and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 15, 1999 and incorporated herein by reference).

10.38		Amended and Restated Agreement of Agreement of Limited Partnership dated as of December 15, 1999 of BJ Services Equipment II, L.P. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K dated December 15, 1999 and incorporated herein by reference).

10.39		Amendment to Directors’ Benefit Plan, effected January 1, 2003 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 and incorporated herein by reference).

†*10.40		Second Amendment effective, March 22, 2001, to BJ Services Company 1999 Employee Stock Purchase Plan.

†*10.41		Fourth Amendment, effective December 4, 2003, to BJ Services Company 1999 Employee Stock Purchase Plan.

†*10.42		First Amendment, effective September 25, 2003, to BJ Services Company Supplemental Executive Retirement Plan.

†*10.43		Charter of the Nominating and Governance Committee of the Board of Directors.

†*10.44		Charter of the Compensation Committee of the Board of Directors.

†*10.45		Charter of the Audit Committee of the Board of Directors.

†*10.46		Board of Directors Corporate Governance Guidelines.

*12.1		Ratio of Earnings to Fixed Charges

*14.1		Code of Ethics

*21.1		Subsidiaries of the Company.

*23.1		Consent of Deloitte & Touche LLP.

*31.1		Section 302 certification for J. W. Stewart

*31.2		Section 302 certification for T. M. Whichard

*32.1		Section 906 certification furnished for J. W. Stewart

*32.2		Section 906 certification furnished for T. M. Whichard