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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended September 30, 2004

OR

For the Transition Period From             to              .

Commission file number 1-10570

BJ SERVICES COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 462-4239

Securities registered pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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  x.

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

At January 14, 2005, the registrant had outstanding 162,455,493 shares of Common Stock, $.10 par value per share. The aggregate market value of the Common Stock on March 31, 2004 (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 $7.0 billion.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held March 24, 2005 are incorporated by reference into Part III of this Form 10-K.

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TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

General

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 for 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, casing and tubular services, production chemical services, and precommissioning, maintenance and turnaround services in the pipeline and process business, including pipeline inspection.

Since its organization, the Company has completed several acquisitions, including the acquisition of OSCA, Inc. (“OSCA”) on May 31, 2002, 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, 2004, 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 52% of its revenue from U.S. operations and 48% from international operations. For geographic revenue and long-lived assets and segment revenue, operating income and identifiable asset details for each of the three years ended September 30, 2004, see Note 8 of the Notes to Consolidated Financial Statements.

The Company conducts its operations through three principal segments:

Pressure Pumping Services

Pressure pumping services are provided by the Company to major and independent oil and natural gas producing companies, as well as national oil companies, for the purpose of completing new oil and natural gas wells, maintaining existing oil and natural gas wells, and enhancing the production of oil and natural gas from formations in reservoirs. Pressure pumping services are provided through the Company’s U.S./Mexico Pressure Pumping Segment and the International Pressure Pumping Segment. These 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.

Cementing Services

The Company’s cementing services, which accounted for approximately 35% of total pressure pumping revenue during fiscal 2004, consists 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 cement slurry is designed to achieve the proper cement set-up time, compressive strength and fluid loss control, and can be modified to address different well depths, downhole temperatures and pressures, and formation characteristics.

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The Company provides central, regional and district laboratory testing services to evaluate slurry properties, which can vary by cement supplier and based on the qualities of 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 primary cementing, or cementing between the casing pipe and the wellbore during the drilling and completion phase of a well. 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.

For revenue by product line for each of the three years ended September 30, 2004, see Note 8 of the Notes to Consolidated Financial Statements.

Stimulation Services

The Company’s stimulation services, which accounted for approximately 63% of total pressure pumping revenue during fiscal 2004, 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 the 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 oil and natural gas 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 the U.S. and internationally over the past several years. These services are designed to improve the flow of oil and natural gas from producing formations and are summarized below.

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 into a cased well at sufficient pressure to fracture the producing formation (“fracturing fluid”). Sand, bauxite or synthetic proppants are suspended in the fracturing fluid 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 equipped 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 pump fleet with new, more efficient and higher horsepower pressure pumping equipment. The Company has made significant progress with this program, which is now approximately 83% complete. During fiscal 2004, the Company expanded this U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing and will begin recapitalizing the pressure pumping equipment in Canada in fiscal 2005.

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.

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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 gradual build-up 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, China, 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 is 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, costlier 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 attached to 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.

Other Oilfield Services

The Company’s other oilfield services accounted for approximately 17% of the Company’s total revenue in fiscal 2004. 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, 2004, 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 provided primarily 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. The Company’s casing and tubular services business has historically been focused in the North Sea and selected international markets outside of North America. However, with the fiscal year 2004 acquisitions of Cajun Tubular Services, Inc. and Petro-Drive,

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a division of Grant Prideco, Inc. (see Note 3 of the Notes to Consolidated Financial Statements), the Company’s business expanded into the Gulf of Mexico and other international markets.

Process and Pipeline Services. The Company provides a wide range of services to the process industry, which includes oil and natural gas production, refineries, gas and petrochemical plants and the power industry. These services cover two main areas: (i) the precommissioning of new plants and (ii) maintenance services to existing plants. The services offered consist primarily of testing, cleaning, drying and inerting, using several different technologies. Nitrogen/helium leak testing is used to locate and quantify small leaks on hydrocarbon systems. Leak testing is used on both new and old facilities to minimize the risk of hydrocarbon leaks, improving safety and minimizing greenhouse gas emissions. Systems can be cleaned by flushing, jetting, pigging or chemical means to ensure debris is removed from the system prior to start-up, thus minimizing damage to expensive process equipment.

Our pipeline services also consist of precommissioning and maintenance services. Due to regulatory requirements or safety concerns, new pipelines are often tested prior to their initial use. Pipeline testing typically involves filling the pipeline with water under operating pressures and drying the pipelines. Pipeline drying is carried out using dry air, nitrogen or vacuum. Many pipelines require cleaning while “on line” both to help ensure the integrity of the pipeline and to maximize product throughput. The Company offers several techniques for this, including gel cleaning, which is used to carry large amounts of debris out of the pipeline, and various solvent treatments to remove debris.

The Company’s pipeline inspection business uses “intelligent pigs” to assist pipeline operators in assessing the integrity of their pipelines. Pigs are mechanical devices that are propelled through a pipeline. The Company has developed two principal pipeline inspection tools: one tool monitors metal loss from the interior pipe wall caused by either corrosion or mechanical damage, and a second tool monitors pipeline geometry (dents, buckles and wrinkles) and position (latitude, longitude and height) using an inertial guidance system which allows the production of as-built maps of the pipeline as well as the calculation of critical strains due to pipeline movement. Using the information collected by these tools, pipeline operators are able to carry out structural analysis to ascertain if the pipeline is fit for purpose.

Production Chemical Services. Production chemical services are provided to customers in the upstream and downstream oil and natural gas businesses. 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. Customers engaged in crude oil production, natural gas processing, raw and finished oil and natural gas product transportation, operating refineries and petrochemical manufacturing use these products. Production 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 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 that 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.

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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.

In July 2004, the Company began the construction of a well screen manufacturing facility in Houston, Texas, which will be completed in the first calendar quarter of 2005. Well screens are sections of perforated pipe wrapped with wire that are integrated into the production tubing and are designed to prevent the flow of gravel into the producing wellbore that is pumped in during the sand control operation (see “Pressure Pumping Services” above). Well screens are critical to the success of wells in unconsolidated sandstone reservoirs and are integrated with the completion program (sand control, completion tools and well screens) for sand control. Well screens are utilized primarily in unconsolidated sandstone reservoirs, mostly in the Gulf of Mexico, the North Sea, Venezuela, Brazil, Trinidad, West Africa, China, Indonesia and India.

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 plug oil and natural gas formations. 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.

Raw Materials & Equipment

Principal materials utilized in pressure pumping include cement, fracturing proppants, acid, guar polymers, nitrogen, carbon dioxide and other bulk chemical additives. The Company purchases its principal materials from several suppliers and produces certain materials 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. The Company is not dependent on any single source of supply for any materials; however, loss of one or more of our suppliers could disrupt production.

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Pressure pumping 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 around the world. Most units are equipped with computerized systems that allow for real-time monitoring and control of the cementing and stimulation 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.

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 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 foreseeable future.

Nitrogen is one of the principal materials utilized in the other oilfield services lines. The Company purchases nitrogen from several suppliers. 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.

Engineering and Support Services

The Company’s research and development organization is divided into seven areas: Product Development, Applied Technology, 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., fracturing fluid and cement slurry). 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.

Applied Technology. The Applied Technology group (ATG) is primarily responsible for supporting technical and engineering applications on a global basis for the five primary service product lines that the Company offers (acidizing, cementing, completion services, coiled tubing and fracturing). In addition to providing engineering support, the ATG is responsible for: improving the internal technology transfer within the Company, developing and maintaining all of the support documentation for the Company’s chemical products and systems, as well as managing and maintaining all of the intellectual property. Another key responsibility of the ATG is to guide and prioritize the technology development based on feedback from operations and direct client interaction.

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 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

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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 provides most of the support and research and development activities for the Company’s coiled tubing services, including coiled tubing drilling technology. The Company is also actively involved in the ongoing development of downhole tools that may be attached to the end of coiled tubing.

Completion Tools Engineering. The completions tools research group 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.

Manufacturing

The Company has three main manufacturing facilities. 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. The Company’s facility in Mansfield, Texas produces certain components and spare parts required for the assembly of downhole completion tools and service tools. In addition, the Company will complete the construction of a well screen manufacturing facility in Houston, Texas in the first calendar quarter of 2005.

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.

Competition

Pressure Pumping Services. There are two primary companies with which the Company competes in pressure pumping services worldwide, Halliburton Energy Services, a division of Halliburton Company, and Schlumberger Ltd. These companies have operations in most areas in which the Company operates. Halliburton Energy Services and Schlumberger are larger in terms of overall pressure pumping revenue. It is estimated that these two competitors, along with the Company, provide approximately 90% of the worldwide 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, technology, service record and reputation in the industry.

Other Oilfield Services. The Company believes that it is one of the largest suppliers of casing and tubular services in the North Sea and has expanded such services into other international markets in the past several years and into the U.S. in fiscal 2004 with the acquisition of Cajun Tubular Services, Inc. and Petro-Drive. The largest worldwide provider of casing and tubular services is Weatherford International, Inc. In addition, the Company competes with Frank’s International Inc. in the Gulf of Mexico and certain international markets. 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. There are several competitors significantly larger than the Company in production 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,

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Schlumberger Limited, Baker Hughes Incorporated and Weatherford International, Inc. The principal methods of competition which apply to the Company’s business are its prices, technology, service record and reputation in the industry.

Markets and Customers

Demand for the Company’s services and products depends primarily upon the number of oil and natural gas wells being drilled (“rig count”), 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 during spring break-up, the Company is not significantly impacted by seasonality. Spring break-up is the period during which snow and ice begin to melt and heavy equipment is not permitted on the roads, resulting in lower drilling activity.

The Company’s principal customers consist of major and independent oil and natural gas producing companies, as well as national oil companies. During fiscal 2004, 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. During the last 10 years, the lowest U.S. rig count averaged 601 in fiscal 1999 and the highest U.S. rig count averaged 1,172 in fiscal 2001. In fiscal 2004, the U.S. rig count averaged 1,155, a 20% increase over fiscal 2003. For the 12 months ended September 30, 2003, the active U.S. rig count averaged 966 rigs, an 11% increase from fiscal 2002. The Company’s management believes that average rig count for fiscal 2005 will be approximately 6% higher than the average rig count in fiscal 2004, essentially flat with average rig count during the quarter ended September 30, 2004 of approximately 1,229 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 approximately 49 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 or minority interests in several joint venture companies, through which it conducts a portion of its international operations.

Many countries in which we operate are subject to political, social and economic risks which may cause volatility within any given country. However, the Company’s revenue is less volatile because we operate in approximately 49 countries, which provides somewhat of a balance. Due to the significant investment in and complexity of 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. During the last 10 years, the lowest international rig count averaged 828 in fiscal 1999 and the highest international rig count averaged 1,184 in fiscal 2004. 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

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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. In January 2004, the Company completed the commissioning of another stimulation vessel, the “Blue Angel,” which is currently under contract and is operating offshore Brazil.

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, currency exchange controls, political instability and other risks. The risk of currency exchange rate fluctuations and its impact on net income is mitigated through the use of natural hedges whereby the Company invoices for work performed in certain countries in both U.S. dollars and local currency. The Company attempts to match the amounts invoiced in local currency with the amount of expenses denominated in local currency.

Employees

At September 30, 2004, the Company had a total of 12,825 employees. Approximately 62% of the Company’s employees were employed outside the United States. At September 30, 2004, the Company had a sufficient number of trained employees to meet customer requirements. In periods of rapidly expanding activity, the Company may increase the number of contract personnel to compensate for any temporary shortages in labor.

Governmental and Environmental Regulation

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 any damage to the surface or sub-surface (including aquifers). 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 certain areas at the Company’s facilities. In addition, the Company maintains insurance for certain environmental liabilities, which the Company believes is reasonable based on its experience and 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 disposal facilities that are owned by third parties but are 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 four such sites. Although the Company’s level of involvement varies at each site, 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 believes that their ultimate resolution should not have a material adverse effect on the Company’s results of operations or financial position.

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Research and Development

The Company’s research and development activities are focused on improving existing products and services and developing new technologies designed to meet industry and customer needs. The Company currently holds numerous patents of varying remaining duration. Although 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 the Company’s ongoing operations. The Company also utilizes technologies owned by third parties 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 overall operations.

Pressure Pumping Services Research & Development

The Company has a history of developing patented, industry-leading well stimulation technologies such as Spectra Frac G^® high-performance fracturing fluid, introduced in 1991, polymer-specific enzyme fluid breakers, first commercialized in the early 1990s, and EZ Clean^®, launched in 1993, a polymer-specific enzyme treatment designed to remediate reservoirs that have been damaged by previous fracturing efforts. In 1998, the Company released Vistar^® low-polymer fracturing fluids capable of providing optimum placement of proppant in the reservoir while minimizing fracture damage. During 2003, the Company introduced LiteProp^™, lightweight proppants (patented and patents pending). These low-density proppants produce greater propped fracture length and conductivity than is produced by conventional proppants placed with the use of heavier gelled fluid systems.

Other stimulation technologies include the patented BJ Sandstone Acid^™ system, introduced in 1994, which is designed to enhance production in sandstone reservoirs and remove damage accumulated during previous fracturing and work over efforts.

The Company also developed AquaCon^™, a relative permeability modifier treatment, which was patented in 1991 and has been demonstrated to be an effective water control system for reducing undesirable water production, while increasing oil or natural gas production. The Company’s patented Liquid Stone^® cement slurry is a premixed cement blend which, unlike conventional cement slurries, is storable in its liquid form for weeks or months prior to use. The slurry is premixed, and no on-site mixing equipment is required. It can be pumped through rig pumps.

Other Oilfield Services Research & Development

The Company has development leading technologies for its coil tubing services. The patented Tornado^™ cleanout system provides an effective method for removing sand and other fill material from wells at much greater efficiencies than previously obtainable. The Roto-Pulse^™ gravel pack cleaning system is used in removing material plugging a gravel pack. During 2001 and 2002, the Company developed the LEGS^™ (lateral entry guidance system) tool for use with coiled tubing operations in horizontal wells. The LEGS^™ tool provides the technology to locate and successfully guide the coil tubing into horizontal wells in order to perform coiled tubing workover operations.

The Company has developed a broad line of completion tool systems, including conventional completions and horizontal well completions in both gravel-packed and conventional configurations. The PAC valve (pressure actuated circulating valve) is a key component enabling interventionless intelligent completion systems. During 2000 and 2001, the Company successfully field tested 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 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 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, 2004, see Note 12 of the Notes to Consolidated Financial Statements.

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Risk Factors

This document and the Company’s other filings with the Securities and Exchange Commission and 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 natural 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:

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Risks from Unexpected Litigation. The Company has insurance coverage against operating hazards, which 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.

In addition, our U.S. operations could be materially affected by severe weather in the Gulf of Mexico. Severe weather, such as hurricanes, may cause:

Credit. If the Company’s credit rating is downgraded below investment grade, holders of the convertible senior notes can require the Company to repurchase these notes (see Note 5 to the Notes to the Consolidated Financial Statements). In addition, such downgrades could increase our costs of obtaining, or make it more difficult to obtain or issue, new debt financing. If our credit rating is downgraded, we could be required to, among other things, pay additional interest under our credit agreements, or provide additional guarantees, collateral, letters of credit or cash for credit support obligations.

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

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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.

Available Information

Information regarding the Company, including corporate governance policies, ethics policies and charters for the committees of the board of directors can be found on the Company’s internet website at http://www.bjservices.com. In addition, 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 Section 13 (a) or 15 (d) of the Exchange Act are made available free of charge on the Company’s internet website on the same day that we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

Executive Officers of the Registrant

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 1979 and was promoted to Director, Human Resources in 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 Division in 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 served as Vice President of Sales for the U.S. Western Division from 1996 until 2002, when he was named Vice President—Technology and Logistics.

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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. From 1998 to 2001, he served in various financial positions in Cooper Energy Services, a division of Cooper Cameron Corporation.

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—U.S. Division in 1991, he served as Region Manager—Western U.S. and Canada.

ITEM 2. PROPERTIES

The Company leases its corporate office located in Houston, Texas. During fiscal 2004, the Company acquired land in Houston, Texas to begin building a new corporate office, which is expected to be completed in December 2005. Properties are either owned or leased and typically serve all of our business lines. These properties are located near major oil and natural gas fields to optimally address our customers’ needs. Administrative offices and facilities have been built on these properties to support our business through regional and district facilities in approximately 200 locations worldwide, none of which are individually significant due to the mobility of the equipment, as discussed in the “Raw Materials and Equipment” section.

In addition, the Company owns three manufacturing facilities. The Company’s research and technology center in Tomball, Texas also houses its main equipment and instrumentation manufacturing facility. The Company’s facility in Mansfield, Texas produces certain components and spare parts required for the assembly of downhole completion tools and service tools. In addition, the Company will complete the construction of a well screen manufacturing facility in Houston, Texas in the first calendar quarter of 2005.

The Company’s equipment consists 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 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 the Consolidated Financial Statements.

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ITEM 3. LEGAL PROCEEDINGS

Litigation

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. Further, through a series of acquisitions, the Company assumed responsibility for certain claims and proceedings made against the Western Company of North America, Nowsco Well Service Ltd., OSCA and other companies whose stock we acquired 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.

Chevron Phillips Litigation

On July 10, 2002, Chevron Phillips Chemical Company (“Chevron Phillips”) filed a lawsuit against the Company 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 the Company has its own patents for remediating damage resulting from drill-in fluids (as opposed to drilling muds) in oil and natural gas formations (products and services which are offered under the registered “MUDZYMES” trademark), the Company approached Phillips for a license of the ‘477 patent. The Company 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 the Company should deal with GMT in obtaining a sublicense. The Company entered into a five year sublicense agreement with GMT in 1997.

Early in 2000, Phillips advised the Company that Phillips had reportedly terminated the license agreement between Phillips and GMT for GMT’s non-payment of royalties and that the Company’s sublicense had also been terminated. Even though the Company believes that its sublicense with GMT was not properly terminated and the Company’s MUDZYMES treatments may not be covered by the ‘477 patent, in 2000, the Company stopped offering its enzyme product for use on drilling mud and drill-in fluids in the U.S. Nevertheless, Chevron Phillips claimed that the use of enzymes in fracturing fluids and other applications in the oil and natural gas industry falls under the ‘477 patent. Further, even though its patent is valid only in the United States, Chevron Phillips requested that the court award it damages for the Company’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 and Chevron Phillips reached a settlement agreement on August 1, 2004 under which the Company purchased the ‘477 patent from Chevron Phillips in exchange for cash and certain royalty payments on the Company’s use of MUDZYMES in the future.

Halliburton—Python Litigation

On June 27, 2002, Halliburton Energy Services, Inc. filed suit against the Company 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 the Company (under the trade name “Python”) and Weatherford infringe two of its patents for a tool constructed of composite material. The lawsuit was filed in the United States District Court for the Northern District of Texas (Dallas). Halliburton requested that the District

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Court issue a temporary restraining order and a preliminary injunction against both Weatherford and the Company 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 filed an appeal with the Court of Appeals for the Federal Circuit. Oral arguments took place on June 10, 2004, and on June 14, 2004, the Court of Appeals issued its ruling affirming the District Court’s opinion. On July 6, 2004, Halliburton submitted both of its patents for re-examination to the U.S. Patent Office, seeking to re-affirm the validity of its patents. The Company has filed its own request for re-examination of the patents. The lawsuit pending in the Northern District of Texas was dismissed on November 16, 2004, at the request of Halliburton. The dismissal was “without prejudice”, meaning that Halliburton has the right to re-file this lawsuit and may do so depending on the outcome of the re-examination process referenced above. The Company has filed a motion with the Court requesting that the Court reinstate the case solely for the purpose of conducting a Markman hearing to construe the construction of the claims in the Halliburton patent. Irrespective of the outcome of the pending motion or the patent re-examination, the Company does not expect the outcome of this matter to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter or future lawsuits, if any, that may be filed.

Halliburton—Vistar Litigation

On March 17, 2000, the Company filed a lawsuit against Halliburton Energy Services in the United States District Court for the Southern District of Texas (Houston). In the lawsuit, the Company alleged that a well fracturing fluid system used by Halliburton infringes a patent issued to the Company in January 2000 for a method of well fracturing referred to by the Company as “Vistar^®”. This case was tried in March and April of 2002. The jury reached a verdict in favor of the Company on April 12, 2002. The jury determined that the Company’s patent was valid and that Halliburton’s competing fluid system, Phoenix, infringed the Company’s patent. The District Court 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 the Company’s favor. On October 17, 2003, the Federal Circuit denied Halliburton’s request for a re-hearing. Halliburton filed a Petition for Writ of Certiorari with the U.S. Supreme Court on January 15, 2004. On April 5, 2004 the Supreme Court notified the parties that it would not hear Halliburton’s appeal. On April 14, 2004, Halliburton transferred the sum of $106.4 million to the Company, representing full payment of the original judgment, certain court costs, and interest accrued through that date. During the quarter ended June 30, 2004, the Company recorded a gain of $86.4 million, net of legal fees ($56 million after taxes) in “Other income/(expense)—net” in the Consolidated Statement of Operations, reflecting receipt of this sum.

Newfield Litigation

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, filed by Newfield Exploration on September 8, 2000, arose out of a blowout that occurred in 1999 on an offshore well owned by Newfield. 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-judgment 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. Oral argument has been scheduled for April of 2005. Great Lakes Chemical Corporation, which formerly

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owned the majority of the outstanding shares of OSCA, has agreed to indemnify the Company 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.

Asbestos Litigation

In August 2004, certain predecessors of the Company were named as defendants in four lawsuits filed in the Circuit Courts of Jones and Smith Counties in Mississippi. These four lawsuits include 118 individual plaintiffs alleging that they suffer various illnesses from exposure to asbestos. The lawsuits assert claims of unseaworthiness, negligence, and strict liability, all based upon the status of the Company’s predecessors as Jones Act employers. These cases include numerous defendants and, in general, the defendents are all alleged to have manufactured, distributed or utilized products containing asbestos. No discovery has been conducted to date, and the Company has not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos while employed by the Company, the capacity in which they were employed, nor their medical condition. Accordingly, the Company is unable to estimate its potential exposure to these lawsuits. The Company and its predecessors in the past maintained insurance which it believes will be available to address any liability arising from these claims. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of these lawsuits to have a material adverse effect on its financial position, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits or additional similar lawsuits, if any, that may be filed.

Environmental

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 $2.7 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.

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 criminal proceedings have been dismissed and the Company entered into a Consent Order (a civil proceeding) regarding this matter on March 24, 2004 with the State of Oklahoma, Department of Environmental Quality. A fine of $50,000 was assessed, $25,000 of which has been paid in cash. The Company expects to receive credit for the balance of the fine by performing cementing services for the Oklahoma Department of Environmental Quality. The Company is also required to pay drum disposal costs of $5,770.

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

No matters were submitted for stockholders’ vote during the fourth quarter of the fiscal year ended September 30, 2004.

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PART II

The Common Stock of the Company began trading on The New York Stock Exchange in July 1990 under the symbol “BJS”. At January 14, 2005, there were approximately 1,803 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:

From its initial public offering in 1990 until 2004, BJ Services did not pay any cash dividends to its stockholders. However, on July 22, 2004, the Company announced the initiation of a regular quarterly cash dividend and declared a dividend of $.08 per common share, paid on October 15, 2004 to stockholders of record at the close of business on September 15, 2004, in the aggregate amount of $12.9 million. The Company anticipates paying cash dividends in the amount of $.08 per common share on a quarterly basis in fiscal 2005. However, our Board of Directors must approve the dividend each quarter and has the ability to change the dividend policy at any time.

At September 30, 2004, there were 173,755,324 shares of Common Stock issued and 161,868,839 shares outstanding. 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 a total of 24,183,000 shares at a cost of $499.0 million through fiscal 2002. There were no such repurchases in fiscal 2004 or 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 the purchase price of its acquisition of OSCA, which closed on May 31, 2002, and for general corporate purposes. There were $419.6 million and $414.9 million outstanding under the convertible senior notes at September 30, 2004 and September 30, 2003, 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

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require the Company to repurchase the notes in April 2005 and again on the 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.

The notes are convertible into common stock of the Company 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, 2004, the accreted conversion price per share would have been $54.17.

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,” as defined under the Rights Plan) 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.

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ITEM 6. SELECTED FINANCIAL DATA

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, 2004 have been derived from the audited consolidated financial statements of the Company, some of which appear elsewhere in this Annual Report on Form 10-K. 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.

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Business

The Company is engaged in providing pressure pumping services and other oilfield services to the oil and natural gas industry worldwide. Services are provided through three segments: U.S./Mexico Pressure Pumping, International Pressure Pumping, and Other Oilfield Services.

The U.S./Mexico and International Pressure Pumping segments provide stimulation and cementing services to the petroleum industry throughout the world. 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, primarily during the drilling and completion phase of a well. See “Business” included elsewhere in this Annual Report on Form 10-K for more information on these operations.

The Other Oilfield Services segment consists of production chemical services, casing and tubular services, process and pipeline services, and completion tools and completion fluids services in the U.S. and select markets internationally.

Recent Developments

In October 2004 the Company received a report from a whistleblower alleging that its Asia Pacific Region Controller had misappropriated Company funds in fiscal 2001. The Company began an internal investigation into the misappropriation and whether other inappropriate actions occurred in the Region. The Region Controller admitted to multiple misappropriations during a 30-month period ended April 2002, and his employment was terminated. The misappropriations identified to date total approximately $9.0 million and have been repaid to the Company. The misappropriated funds were recorded as an expense in the Consolidated Statement of Operations in prior periods; therefore, no restatement for the misappropriation is required. As a result, the Company expects to record $9.0 million as Other Income in the Consolidated Condensed Statement of Operations for the quarter ending December 31, 2004.

The Company has conducted a comprehensive review of the Asia Pacific Region’s balance sheet and we have determined that excess liabilities had accumulated over a period of years which still existed at September 30, 2004 in the amount of $12.2 million. The following adjustments have been recorded in accordance with GAAP and Company policy:

The net effect of these adjustments has been reported in Other Income in the Consolidated Statement of Operations for the year ended September 30, 2004.

Based on our review of the facts and circumstances surrounding these accounting adjustments, we believe the amounts identified were not quantitatively or qualitatively material to the financial statements presented in this annual report on Form 10-K. As such, we have recorded the correction of these amounts in fiscal 2004 since they are not individually or in the aggregate, material to the prior periods or the current year.

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Based on results of the investigation to date, the misappropriations and accounting adjustments depicted above were possible because of internal control operating deficiencies, including approval procedures that were not being followed, as required by Company policy, with respect to cash disbursements and proper support for accounting entries. The Asia-Pacific region followed an unauthorized practice of maintaining a supply of blank checks that were pre-signed by managers otherwise responsible for reviewing appropriate documentation in support of approved disbursements.

In addition, certain employees responsible for ensuring that payment disbursements were properly documented and approved prior to authorizing the initiation of a check or an electronic funds transfer did not comply with company policies in performance of this function. The operating effectiveness of our controls was further compromised in the Asia-Pacific region as personnel responsible for ensuring compliance with Company policies were aware of unapproved payments that lacked proper support and did not take appropriate action to report the practice.

The Company believes that these operating control deficiencies constitute a significant control deficiency and has discussed these operating deficiencies, as well as our corrective actions and plans, with the Audit Committee.

During fiscal 2002, the Company implemented policy changes worldwide for disbursements. Corporate officer authorization was required for disbursements over specified thresholds, and agreements have been established with our banks specifying the signing limits of regional managers. Transactions in excess of designated limits of authority require the approval of a corporate officer prior to the banks’ processing of transactions.

In October 2004, the Company’s management conducted discussions with senior accounting personnel on a world-wide basis on how the misappropriation occurred and reminding them of the Company’s policies and procedures for disbursing funds. The Company’s management also required positive written affirmation that the practice of maintaining signed blank checks, in contravention of Company policy, was not being conducted elsewhere. The Company has assigned an acting Controller to the Asia Pacific region and is taking necessary action to ensure the review and approval processes are being followed as contemplated by the documented policies and procedures.

The Company is reviewing its control policies and procedures and is considering enhancements to its internal control system.

The Company is continuing to investigate whether additional funds were misappropriated beyond the $9 million identified to date and investigate other possible inappropriate actions. As the Company continues its investigation, further adjustments may be recorded in the Consolidated Statements of Operations, but no material adjustments are known at this time.

In October 2004, the Company also received whistleblower allegations that illegal payments to foreign officials were made in the Asia Pacific Region. The Audit Committee of the Board of Directors engaged independent counsel to conduct a separate investigation to determine whether any such illegal payments were made. That investigation, which is continuing, has found information indicating that illegal payments to government officials in the Asia Pacific Region aggregating in excess of $1.5 million may have been made over several years.

Market Conditions

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. These market

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factors often lead 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. Historical market conditions are reflected in the table below for the twelve months ended September 30:

U.S. Rig Count

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. During the last 10 years, the lowest U.S. rig count averaged 601 in fiscal 1999 and the highest U.S. rig count averaged 1,172 in fiscal 2001. The Company’s management estimates that the average U.S. rig count for fiscal 2005 will be approximately 6% higher than the average rig count in fiscal 2004.

International Rig Count

Many countries in which we operate are subject to political, social and economic risks which may cause volatility within any given country. However, the Company’s revenue is less volatile because we operate in approximately 49 countries, which provides somewhat of a balance. Due to the significant investment and complexity of 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. During the last 10 years, the lowest international rig count (including Canada) averaged 828 in fiscal 1999 and the highest international rig count averaged 1,184 in fiscal 2004. During fiscal 2004, active international drilling rigs (excluding Canada) drilling activity averaged 818, compared to 761 rigs in fiscal 2003 and 730 rigs in fiscal 2002. The Company expects international drilling activity outside of Canada to remain relatively flat for fiscal 2005 compared to fiscal 2004.

Canadian drilling activity averaged 366 active drilling rigs in fiscal 2004, compared to 341 rigs in fiscal 2003 and 265 rigs in fiscal 2002. The Company anticipates Canadian revenue to increase based on an expected 5% increase in average rig count during fiscal 2005, over fiscal 2004.

Acquisitions

On November 26, 2003, the Company completed the acquisition of Cajun Tubular Services, Inc. (“Cajun”) for a total purchase price of $8.3 million (net of cash). Cajun, located in Lafayette, Louisiana, provides tubular running, testing and torque monitoring services to the Gulf of Mexico market. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

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

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provider of hydraulic and diesel hammer services to the Gulf of Mexico market and select markets internationally. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

The Company is in the process of completing its review and determination of the fair values of the assets acquired. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. The pro forma financial information for these acquisitions is not included in this Annual Report on Form 10-K as they were not material to the Company.

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.

Results of Operations

The following table sets forth selected key operating statistics reflecting the Company’s financial results for the twelve months ended September 30 (in millions):

Consolidated Revenue and Operating Income: Increased drilling activity for the U.S. and Canada, pricing improvement in the U.S. and improved revenue from all service lines in the Other Oilfield Services segment are the primary reasons for the increase in revenue for fiscal 2004, compared to fiscal 2003. Increased activity, international geographic expansion and acquisitions are the primary reasons for the increase in the Other Oilfield Services segment. These revenue increases were partially offset by activity decreases in some international locations.

Fiscal 2004 operating income also benefited from the increased revenue described above, but was hindered by activity declines in higher margin locations, decreased pricing and a change in product mix in certain international markets. For fiscal 2004, consolidated operating income margins improved to 16.9% from 13.7% reported in fiscal 2003.

For fiscal 2003, the increase in consolidated revenue was primarily from increased drilling activity in the U.S. and Canada. 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.

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For fiscal 2003, operating income margins decreased to 13.7% from 14.1% reported for fiscal 2002, due primarily to lower U.S. pricing, which was partially offset by increased Canadian activity.

See discussion below on individual segments for further revenue and operating income variance details.

U.S./Mexico Pressure Pumping Segment

Results for fiscal 2004 compared to fiscal 2003

The increase in revenue is primarily a result of an increase in the combined U.S. and Mexico drilling activity of 20% over fiscal 2003 and improved pricing in the U.S. As of September 30, 2004, approximately 62% of our customers were on the new U.S. price book, which became effective on May 1, 2004.

The increase in operating income was primarily due to the increases in revenue described above, coupled with labor efficiency gains. Labor efficiencies were achieved through an increase in activity without a proportional increase in headcount, thereby increasing employee utilization per job. The headcount for fiscal 2004 increased 6% compared to fiscal 2003, with revenue increasing 29%. Labor efficiencies are also being obtained through utilization of newer, more efficient and more modern equipment (see the “Business” section for information on the U.S. fleet recapitalization initiative). In addition, the pricing increase described above directly increases operating income without any associated cost.

Results for fiscal 2003 compared to fiscal 2002

Revenue increased primarily due to an 11% increase in U.S. drilling activity, partially offset by lower U.S. prices in fiscal 2003 compared to fiscal 2002.

Operating income increased as a result of activity increases and labor efficiencies noted previously. The headcount for fiscal 2003 decreased 2% compared to fiscal 2002, with revenue increasing 9%. These increases were mostly offset by a deterioration in prices the Company received for its pressure pumping services compared to fiscal 2002. The deterioration in prices occurred primarily in the first quarter of fiscal 2003.

Outlook

During fiscal 2005, the Company estimates the average U.S. rig count will be approximately 6% higher than the average rig count in fiscal 2004. In determining forecasted rig activity, management reviews proprietary projected rig count data provided by a third party and has discussions with customers regarding their expectations for upcoming service requirements. Management analyzes the data obtained and an internal rig count projection is determined. Under normal circumstances and depending on the geographic mix and types of services provided, an increase in rig count will usually result in an increase in the Company’s revenue. The Company also anticipates increasing headcount 10-15% in the U.S. during fiscal 2005.

We expect market disruption in Mexico compared to activity levels experienced in 2004 as our customer in Mexico resolves budget management issues. In addition, there has been much price competition in Mexico recently. As a result, we anticipate Mexico revenue to decline 25-30% in fiscal 2005, compared to revenue in fiscal 2004.

The Company issued a price book increase for its U.S. pressure pumping operations. The increase averages 7% above the former price book in the U.S. and was effective May 1, 2004. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

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International Pressure Pumping Segment

Results for fiscal 2004 compared to fiscal 2003

Canadian operations were the primary reason for the increase in revenue. Canadian revenue increased 31% compared to the same period in the prior year, with drilling activity up 7%. The Canadian increase in revenue is attributed to activity related gains of 16%, price improvement of 3% and favorable foreign exchange translation of 12%. Other countries contributing to the revenue increase include Russia, India, and the Company’s stimulation vessel in the North Sea. Russia revenue increased 25% from increased stimulation activity, while activity increases in India resulted in a 49% increase in revenue. These increases in revenue were partially offset by decreased revenue in Saudi Arabia, Norway, Nigeria and Colombia. Fracturing activity was suspended in Saudi Arabia during the first four months of fiscal 2004, in addition to pricing pressure. Norway revenue declined 29% as a result of a decrease in coiled tubing activity and a change in the services required by customers. Activity declines in Nigeria resulted in a 31% decrease in revenue. In Colombia, major customers have curtailed their drilling programs and, primarily as a result, revenue decreased 27%.

Operating income increased as a result of the improved revenues in Russia, India and Canada described above. While the weakening U.S. dollar increased Canadian revenue, it had minimal impact on operating income as most of our expenses are denominated in Canadian dollars. The increase in operating income from Canada is primarily due to the activity increases, which also resulted in improved labor utilization efficiencies. Labor efficiencies were achieved by increasing revenue generated per employee by 14%, compared to the same period in fiscal 2003. These operating income increases were mostly offset by the impact of activity declines in Saudi Arabia, Norway, and Colombia where the Company has historically enjoyed higher margins. In addition, operating income in Africa was negatively impacted, primarily as a result of activity reductions in Nigeria from our major customers. Cost reductions in Africa and Norway and Latin America have been initiated to accommodate current activity levels, resulting in restructuring costs incurred in fiscal 2004 which did not occur in fiscal 2003. This segment also had a decline in operating profit margins due to events causing the stimulation vessel in the North Sea to be temporarily idle. In addition to emergency maintenance experienced during the fourth fiscal quarter of 2004, the customer that contracted for the vessel shut down its operations in the North Sea for two months during the quarter ended June 30, 2004. Since there are significant fixed costs associated with operating the stimulation vessel, there was a decline in operating profit as a result of these two events in the latter half of fiscal 2004.

Results for fiscal 2003 compared to fiscal 2002

Fiscal 2003 revenue in Canada, Russia, Europe and Africa, Asia Pacific and the Middle East improved when compared to fiscal 2002, with the Canadian operations being the primary contributor to the increase in revenue. 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 a coiled tubing company (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, revenue was lower in India resulting from activity declines.

Although 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 utilization efficiencies. The headcount for fiscal 2003 decreased 1% compared to fiscal 2002, with revenue increasing 13%.

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Outlook

Compared to levels experienced during fiscal 2004, the Company expects international revenue outside of Canada to remain relatively constant for fiscal 2005. The Company anticipates Canadian revenue to increase based on an expected 5% increase in average rig count during fiscal 2005, over fiscal 2004.

The Company has issued a price book increase for its Canadian pressure pumping operations. The increase averages 5% above the former price book in Canada and was effective August 1, 2004. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

Other Oilfield Services Segment

Results for fiscal 2004 compared to fiscal 2003

Excluding the impact of the Cajun and Petro-Drive acquisitions, revenue would have increased 19% in fiscal 2004. Revenue from each service line within Other Oilfield Services increased during fiscal 2004. Due to the high oil prices experienced in fiscal 2003, many refineries deferred their maintenance shut-downs last year until fiscal 2004, even though oil prices remained high. As a result, process and pipeline services did not perform as many process services in fiscal 2003 as in fiscal 2004. The increase in the completion tools business line was primarily achieved through an increase in customer activity in the Gulf of Mexico. International expansion is the reason for the increase in our revenue for the completion fluids and casing and tubular service business lines.

Excluding the impact of the Cajun and Petro-Drive acquisitions, operating income would have increased 7% in fiscal 2004. The increase is primarily attributable to completion tools and tubular business lines for the reasons described above. This increase was partially offset by decreased margins in the process and pipeline service business and the completion fluids business. The process and pipeline service business had higher margin projects in fiscal 2003, when compared to fiscal 2004. While revenue increased in Norway from our completion fluids business, this increased activity was in lower margin product sales compared to the prior year.

Results for fiscal 2003 compared to fiscal 2002

The increase in revenue 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.

The increase in operating income 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 13%, 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.

Outlook

We expect revenue from completion tools and completion fluids to increase 10-15% in fiscal 2005, and tubular services to increase 5-10%. This estimate is primarily attributable to expansion of completion tools to new international markets and expansion of casing and tubular services in the U.S. and internationally. Process and pipeline services revenue is expected to decline by 10% as the Company will focus its efforts on obtaining projects with better margins.

Other Expenses

Depreciation Expense: Depreciation expense is included in Cost of Sales and Services on the Consolidated Statement of Operations. For fiscal 2004, depreciation expense increased by $5.5 million, compared to fiscal

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2003. For fiscal 2003, depreciation expense increased by $15.3 million, compared to fiscal 2002. These increases in depreciation expense are primarily a result of the Company’s increased capital spending levels and additional depreciation expense on certain capital improvements on leased equipment.

Research and engineering, marketing and general and administrative expenses: The aggregate of these expenses increased 13% for fiscal 2004, compared to fiscal 2003. As a percent of revenue, each of these expenses was consistent with the same periods of the prior year. The following table sets forth the Company’s other operating expenses as a percentage of revenue:

Interest Expense and Interest Income: Interest expense increased $7.0 million for fiscal 2003, compared to fiscal 2002. This is a result of the issuance of convertible debt in April 2002, used to finance a portion of the OSCA acquisition.

Interest income increased $3.9 million for fiscal 2004, compared to fiscal 2003. This increase resulted from an increased cash and cash equivalents balance.

Other (Expense) Income, net: For fiscal 2004, the Company recorded a gain of $86.4 million for the Halliburton award (see Note 10 of the Notes to the Consolidated Financial Statements). In addition, $12.2 million was recorded for the reversal of excess liabilities in the Asia-Pacific region (see Recent Developments and Note 16 of the Notes to the Consolidated Financial Statements). For fiscal 2003, compared to fiscal 2002, other expense, net increased $0.5 million. This increase is a result of gains from insurance recoveries in 2002. For additional details of this account, see Note 12 of the Notes to the Consolidated Financial Statements.

Income Taxes: The effective tax rate was 30.7% for fiscal 2004, down from 31.7% experienced in fiscal 2003. This is primarily due to business tax credits that were realized during the third quarter of fiscal 2004. 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 fiscal 2003, compared with 34.1% for fiscal 2002.

Liquidity and Capital Resources

Historical Cash Flow

The following table sets forth the historical cash flows for the twelve months ended September 30 (in millions):

Fiscal 2004

The Company’s working capital increased $42.8 million at September 30, 2004 compared to September 30, 2003, primarily as a result of the increase in cash and cash equivalents, short-term investments and accounts receivable, partially offset by an increase in accounts payable and the reclassification of the convertible senior

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notes to short-term (see Note 5 of the Notes to the Consolidated Financial Statements). Cash and cash equivalents, plus short-term investments, increased $377.0 million since September 30, 2003 as a result of increased activity which resulted in positive cash flow from operations, proceeds from the exercise of stock options and $86.4 million in connection with the Halliburton award (see Note 10 of the Notes to the Consolidated Financial Statements). Accounts receivable increased $78.0 million and accounts payable increased $31.5 million primarily as a result of an increase in U.S. revenue.

The decrease in cash flow from investing was primarily attributable to the purchase of U.S. treasury bills and notes for $229.9 million in May 2004, which have maturities between six and ten months.

During fiscal 2004, due to the poor market performance of the pension plan investments in fiscal 2001 and 2002, the Company made required pension contributions of $10.4 million, and made a discretionary contribution of an additional $9 million.

On July 22, 2004, the Company announced the initiation of a regular quarterly cash dividend and declared a dividend of $.08 per common share, paid on October 15, 2004 to stockholders of record at the close of business on September 15, 2004 in the aggregate amount of $12.9 million.

Fiscal 2003

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. Accounts receivable increased $110.8 million and accounts payable increased $56.4 million as a result of increased activity. As a result of higher taxable income in fiscal 2003 and utilizing most of our net operating loss carryforwards, our current tax liability increased $49.8 million.

The decreases in cash flow used in investing and cash flow provided from financing in fiscal 2003 compared to fiscal 2002 was primarily from the issuance of the senior convertible notes to fund the acquisition of OSCA, Inc. in fiscal 2002. In addition, the Company repurchased treasury stock in fiscal 2002 (see Note 14 of the Notes to the Consolidated Financial Statements).

Liquidity and Capital Resources

Cash flow from operations is expected to be our primary source of liquidity in fiscal 2005. Our sources of liquidity also include cash and cash equivalents of $424.7 million at September 30, 2004, short-term investments in U.S. treasury securities of $229.9 million, and the available financing facilities listed below (in millions):

In June 2004, the Company replaced its then existing credit facility with a revolving credit facility (the “Revolving Credit Facility”) that permits borrowings up to $400 million in principal amount. The Revolving Credit Facility includes a $50 million sublimit for the issuance of standby letters of credit and a $20 million sublimit for swingline loans. Swingline loans have short-term maturities and the remaining amounts outstanding under the Revolving Credit Facility become due and payable in June 2009. Interest on outstanding borrowings is charged based on prevailing market rates. The Company is charged various fees in connection with the Revolving Credit Facility, including a commitment fee based on the average daily unused portion of the commitment, totalling $0.5 million in fiscal 2004. In addition, the Revolving Credit Facility charges a utilization

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fee on all outstanding loans and letters of credit when usage of the Revolving Credit Facility exceeds 33%, though there were no such charges in fiscal 2004. There were no outstanding borrowings under the Revolving Credit Facility at September 30, 2004.

The Revolving 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.

On December 29, 2004, the Company gave notice of default to the lenders under its Revolving Credit Facility for its failure to comply with its covenants to timely provide to the lenders its annual, audited financial statements and certain other reports. Similar default notices were given to the entities to whom obligations are owed under the equipment financing partnerships referenced below on January 13, 2005. However, under all of these debt instruments, the earliest date on which an Event of Default permitting acceleration of indebtedness or termination of the credit facilities by the lenders could occur as a result of the delay in furnishing such financial statements and reports is January 29, 2005. Since the Company expects to furnish such financial statements and other reports before that date, the defaults will be cured such that no Event of Default will occur under such debt instruments as a result of this delay.

As of January 26, 2005, the Company is in compliance with all of the financial covenants, and has no borrowings under, under its Revolving Credit Facility and has cash and cash equivalents and short-term investments in excess of its other indebtedness.

In addition to the Revolving Credit Facility, the Company had $94.2 million in various unsecured, discretionary lines of credit at September 30, 2004, which expire at various dates within the next 12 months. 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 was $3.8 million and $5.9 million in outstanding borrowings under these lines of credit at September 30, 2004 and September 30, 2003, respectively.

Management believes that cash flow from operations combined with cash and cash equivalents, short-term investments, the Revolving Credit Facility, and other discretionary credit facilities provide the Company with sufficient capital resources and liquidity to manage its routine operations, meet debt service obligations, fund projected capital expenditures, repurchase common stock, pay a regular quarterly dividend and support the development of our short-term and long-term operating strategies. 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.

At September 30, 2004 and September 30, 2003, the Company had issued and outstanding $78.9 million of unsecured 7% Series B Notes due February 1, 2006, net of discount.

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 $419.6 million and $414.9 million outstanding under the convertible senior notes at September 30, 2004 and September 30, 2003, 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 in April 2005 and again on the 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.

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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, 2004, the accreted conversion price per share would have been $54.17.

Cash Requirements

As described earlier, holders of the convertible senior notes can require the Company to repurchase the notes in April 2005. The Company has the option to settle the repurchase price in cash or stock. Should the holders call the notes, the Company has the ability and intent to satisfy the obligation using cash.

The Company anticipates capital expenditures to be between $270 and $290 million in fiscal 2005, compared to $201 million in 2004, $167 million in 2003 and $179 million in 2002. The 2005 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. In 1998, the Company embarked on a program to replace its aging U.S. fracturing pump fleet with new, more efficient and higher horsepower pressure pumping equipment. The Company has made significant progress with this program, which is now approximately 83% complete. During fiscal 2004, the Company expanded this U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing and will begin recapitalizing the pressure pumping equipment in Canada in fiscal 2005. The actual amount of 2005 capital expenditures will depend primarily on maintenance requirements and expansion opportunities.

In fiscal 2005, the Company’s minimum pension and postretirement funding requirements are anticipated to be approximately $9.0 million.

Due to the expiration of favorable tax provisions on depreciation and the useage of tax credits and other tax attributes in fiscal 2004, we expect an incremental increase to cash paid for income taxes of at least $45 million in fiscal 2005.

The Company anticipates paying cash dividends in the amount of $.08 per common share on a quarterly basis in fiscal 2005. Based on the shares outstanding on September 30, 2004, the aggregate annual amount would be $52.0 million. However, our Board of Directors must approve the dividend each quarter and has the ability to change the dividend policy at any time.

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The following table summarizes the Company’s contractual cash obligations as of September 30, 2004 (in thousands):

The Company expects that cash and cash equivalents, short-term investments (maturing in fiscal 2005), and cash flow from operations will generate sufficient cash flow to fund all of the cash requirements described above.

Off Balance Sheet Transactions

In December 1999, the Company contributed certain pumping service equipment to a limited partnership. The Company owns a 1% interest in the 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 Cash Obligations table above. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, the Company was not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 13 years. The balance of the deferred gain was $26.6 million and $33.9 million as of September 30, 2004 and September 30, 2003, 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 July 2004 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 $3.3 million. 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 Company owns a 1% interest in the limited partnership. The equipment is used to provide services to the

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Company’s customers for which the Company pays a service fee over a period of at least eight years, but not more than 13 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 Cash Obligations table above. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, the Company was not deemed to be the primary beneficiary, and therefore, consolidation was not required. The transaction resulted in a gain that is being deferred and amortized over 12 years. The balance of the deferred gain was $0.4 million and $16.0 million as of September 30, 2004 and September 30, 2003, 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 and again in July 2004 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 in October 2003 and $1.3 million in July 2004. In June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million.

Contractual Obligations

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 the length of the service 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, 2004 (in thousands):

Critical Accounting Policies

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 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

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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: The Company accounts for goodwill in accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). 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, terminal value multiples, rig count, Company price book increases or decreases, and inflation rate.

No impairment adjustment was necessary to the Company’s $885.9 million goodwill balance at September 30, 2004. See Note 2 of the Notes to the Consolidated Financial Statements for more information on goodwill.

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

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required to make an evaluation of critical assumptions such as discount rate, expected long-term rate of return on plan assets 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.

In fiscal 2005, the Company will have a minimum pension funding requirement of $9.0 million. We expect to fund this amount with cash flows from operating activities. 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 30.7%, 31.7%, and 34.1% for the years ended September 30, 2004, 2003, and 2002, 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.

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.

Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123-Revised 2004 (“SFAS 123(R)”), Share-Based Payment. This is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. As noted in our employee stock-based compensation accounting policy described above, the Company does not record compensation expense for stock-based compensation. Under SFAS 123(R), the Company will be required to measure the cost of employee services received in exchange for stock based on the grant-date fair value (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award (usually the vesting period). The fair value will be estimated using an option-pricing model. Excess tax benefits, as defined in SFAS 123(R), will be recognized as an addition to paid-in capital. This is effective as of the beginning of the first interim or annual

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reporting period that begins after June 15, 2005. The Company is currently in the process of evaluating the impact of SFAS 123(R) on its financial statements, including different option-pricing models. The pro forma table in Note 2 of the Notes to the Consolidated Financial Statements illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123.

In December 2003, the Financial Accounting Standards Board (“FASB”) issued an exposure draft amending FASB Statement No. 128, Earnings per Share (“SFAS 128”). The exposure draft would amend the computational guidance of SFAS 128. When applying the treasury stock method for year-to-date diluted earnings per share (“EPS”), SFAS 128 requires that the number of incremental shares included in the denominator be determined by computing a year-to-date weighted average of the number of incremental shares included in each quarterly diluted EPS computation. Under this proposed Statement, the number of incremental shares included in year-to-date diluted EPS would be computed using the average market price of common shares for the year-to-date period. The proposed Statement also would eliminate the provisions of SFAS 128 that allow an entity to rebut the presumption that contracts with the option of settling in either cash or stock will be settled in cash. In addition, the proposed Statement would require that shares to be issued upon conversion of a mandatorily convertible security be included in the computation of basic EPS from the date that conversion becomes mandatory. Under the current SFAS 128, we have excluded the convertible senior notes from our diluted EPS calculation as we have the ability and intent to settle the obligation with cash instead of stock. If implemented as proposed, we would be required to include the convertible senior notes in the diluted EPS calculation, which could have a material effect on our diluted EPS. The provisions of the final Statement could differ from this disclosure; as a result, the actual application of any final Statement could result in effects that are different than those discussed.

In December 2003, the FASB issued FASB Statement No. 132-Revised 2003 (“SFAS 132R”), Employers’ Disclosures about Pensions and Other Postretirement Benefits. This standard increases the existing disclosure requirements by requiring more details about pension plan assets, benefit obligations, cash flows, benefit costs and related information. Companies are required to segregate plan assets by category, such as debt, equity and real estate, and to provide certain expected rates of return and other informational disclosures. SFAS 132R also requires companies to disclose various elements of pension and postretirement benefit costs in interim-period financial statements for quarters beginning after December 15, 2003 (see Note 9 of the Notes to the Consolidated Financial Statements). We have complied with the disclosure requirements of SFAS 132R.

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. In December 2003, the FASB issued FIN 46(R) which revised certain provisions in the original interpretation and permitted multiple effective dates based upon the nature and formation date of the variable interest entity. Adoption of the provisions of FIN 46 did not have a material impact on the Company’s financial position or results of operations (see Note 10 of the Notes to the Consolidated Financial Statements).

In October 2004, the American Jobs Creation Act of 2004 (the “Act”) was signed into law. The Act contains new provisions that may impact the Company’s U.S. income tax liability in future years. The FASB has proposed accounting guidance for certain of the Act’s provisions by issuing two draft FASB Staff Positions (FSPs 109-a and 109-b) dealing with the deduction the Act offers to domestic manufacturers, and the temporary lower tax rate on repatriated foreign earnings. As drafted, the FSPs would be effective immediately upon final issuance. The Company is currently analyzing those provisions and will reflect any tax effect in the period in which the effect becomes probable.

Non-GAAP Financial Measures

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

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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 measure used by the Company is free cash flow.

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.

Forward Looking Statements

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 this Annual Report on Form 10-K.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, 2004 rates, the Company’s combined interest expense to third parties would increase by a total of $1,799 each month in which such increase continued. At September 30, 2004, the Company had issued fixed-rate debt of $498.5 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 approximately $18.5 million if interest rates were to decline by 10% from their rates at September 30, 2004.

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, 2004. When the Company believes prudent, the Company enters into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were no such forward foreign exchange contracts at September 30, 2004. The expected maturity dates and fair value of our market risk sensitive instruments are stated below (in thousands). All items described are non-trading and are stated in U.S. dollars.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Stockholders of BJ Services Company:

We have audited the accompanying consolidated statements of financial position of BJ Services Company and subsidiaries (the “Company”) as of September 30, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and other comprehensive income, and cash flows for each of the three years in the period ended September 30, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of BJ Services Company and subsidiaries at September 30, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/    DELOITTE & TOUCHE LLP

Houston, Texas

January 26, 2005

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BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS

The accompanying notes are an integral part of these consolidated financial statements

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BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

ASSETS