Form 10-K

10-K 1 d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended September 30, 2005

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

For the Transition Period From to .

Commission file number 1-10570

BJ SERVICES COMPANY

(Exact name of registrant as specified in its charter)


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


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

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

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


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

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 ¨.

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

At December 6, 2005, the registrant had outstanding 323,802,752 shares of Common Stock, $.10 par value per share. The aggregate market value of the Common Stock on March 31, 2005 (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 $8.4 billion.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held January 31, 2006 are incorporated by reference into Part II and Part III of this Form 10-K.

TABLE OF CONTENTS


			Page
PART I

	Item 1.	Business	3
	Item 2.	Properties	17
	Item 3.	Legal Proceedings	17
	Item 4.	Submission of Matters to a Vote of Security Holders	20

PART II

	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
	Item 6.	Selected Financial Data	23
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	42
	Item 8.	Financial Statements and Supplementary Data	43
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
	Item 9A.	Controls and Procedures	82
	Item 9B.	Other Information	82

PART III

	Item 10.	Directors and Executive Officers of the Registrant	83
	Item 11.	Executive Compensation	83
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83
	Item 13.	Certain Relationships and Related Transactions	83
	Item 14.	Principal Accountant Fees and Services	83

PART IV

	Item 15.	Exhibits and Financial Statement Schedules	84

PART I

ITEM 1. BUSINESS

General

BJ Services Company (the “Company”), whose operations trace back to the Byron Jackson Company (founded in 1872), was organized in 1990 under the corporate laws of the state of Delaware. The Company is a leading worldwide provider of pressure pumping and other oilfield services for the petroleum industry. 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 May 2002 acquisition of OSCA, Inc. (“OSCA”), a completion services (pressure pumping), completion tools and completion fluids company based in Lafayette, Louisiana, with operations primarily in the U.S., Gulf of Mexico, Brazil and Venezuela.

During the year ended September 30, 2005, the Company generated approximately 84% of its revenue from pressure pumping services and 16% from other oilfield services. Over the same period, the Company generated approximately 56% of its revenue from U.S. operations and 44% from international operations. For segment and geographic information for each of the three years ended September 30, 2005, see Note 8 of the Notes to Consolidated Financial Statements.

The Company conducts its operations through three principal segments:

•

U.S./Mexico Pressure Pumping Services. This segment includes pressure pumping services derived from the Company’s activities in the U.S. and Mexico.

•

International Pressure Pumping Services. This segment includes pressure pumping services derived from the Company’s activities outside of the U.S. and Mexico.

•

Other Oilfield Services. This segment includes the Company’s other oilfield services: (1) casing and tubular services, (2) process and pipeline services, (3) production chemical services, (4) completion tools, and (5) completion fluids.

Pressure Pumping Services

The Company’s pressure pumping services consist of cementing services and stimulation services. Stimulation services includes fracturing, acidizing, sand control, nitrogen services, coiled tubing, and service tools. The Company provides pressure pumping services to major and independent oil and natural gas producing companies, as well as national oil companies. The Company’s pressure pumping services are used to complete new oil and natural gas wells, maintain existing oil and natural gas wells, and enhance the production of oil and natural gas from formations in reservoirs. 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 30% of total pressure pumping revenue during fiscal 2005, 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. The

slurry can be modified to address different well depths, downhole temperatures and pressures, and formation characteristics.

The Company provides central, regional and district laboratory testing services to evaluate cement slurry properties, which can vary by cement supplier and local water sources. The Company’s field engineers develop job design recommendations 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.

Stimulation Services

The Company’s stimulation services, which accounted for approximately 67% of total pressure pumping revenue during fiscal 2005, consist of fracturing, acidizing, sand control, nitrogen services, 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.

The Company believes that as oil and natural gas production continues to decline in key producing fields in 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, which are designed to improve the flow of oil and natural gas from producing formations, 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 (“fracturing fluid”) into a cased well at sufficient pressure to fracture the producing formation. Sand, bauxite or synthetic proppants are suspended in the fracturing fluid and are pumped into the fracture to prop the fracture open. In some cases, fracturing is performed using an acid solution pumped under pressure without a proppant or with small amounts of proppant. The main components in the 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 adding new equipment; however much of the older equipment still remains in operation due to the increases in market activity in the U.S. During fiscal 2004, the Company expanded this U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment, and approximately 30% of this equipment has been replaced through fiscal 2005. Recapitalization of the Company’s pressure pumping equipment in Canada that began in fiscal 2005 is approximately 25% complete at the end of 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 provides technical evaluation and job design recommendations for the customer as an integral element of its fracturing service. Technological developments in the industry over the past several years have focused on proppant concentration control (i.e., proppant density), liquid gel concentrate capabilities, computer design and monitoring of jobs and cleanup properties for fracturing fluids. The Company has introduced equipment and products to respond to these technological advances.

Acidizing. Acidizing enhances the flow rate of oil and natural gas from wells that experience reduced flow caused by formation damage from drilling or completion fluids or the gradual build-up of materials that restrict the flow in 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 performed primarily in unconsolidated sandstone reservoirs, mostly in the Gulf of Mexico, the North Sea, Venezuela, Brazil, Trinidad, West Africa, China, Indonesia and India. The Company’s completion tools, as described elsewhere herein, are often utilized in conjunction with sand control services.

Nitrogen. Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, the use of nitrogen is effective in displacing fluids in various oilfield applications, including underbalanced drilling. However, nitrogen is principally used 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 is wound or coiled on a large reel on a truck or skid-mounted unit. Due to the small diameter of coiled tubing, it can be inserted into existing production tubing and used to perform workovers without using a larger, costlier workover rig. The principal advantages of employing coiled tubing in a workover include (i) not having to cease production from the well (“shut-in”), thus reducing the risk of formation damage to the well, (ii) being able to move continuous coiled tubing in and out of a well significantly faster than conventional pipe, which must be jointed and unjointed, (iii) having the ability to direct fluids into a wellbore with more precision, allowing for localized stimulation treatments, (iv) providing a source of energy to power a downhole motor or manipulate downhole tools and (v) enhancing 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 from the Company by customers. 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 16% of the Company’s total revenue in fiscal 2005. This segment consists of casing and tubular services, process and pipeline services, production chemicals, and, with the acquisition of OSCA in May 2002, completion tools and completion fluids services in the U.S. and select markets internationally.

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 a wellbore and to seal various zones in a well. These services are provided primarily during the drilling and completion phases of a well. Production tubing is run inside the casing and 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. The fiscal 2004 acquisitions of Cajun Tubular Services, Inc. and Petro-Drive, a division of Grant Prideco, Inc. (see Note 3 of the Notes to Consolidated Financial Statements), expanded the Company’s business 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, and gas and petrochemical plants, and to the power industry. These services cover two main areas: (i) the precommissioning of new plants and (ii) maintenance to existing plants. The primary services offered are testing, cleaning, drying and inerting pipework and pipelines. 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 treatment to ensure debris is removed from the system prior to start-up, thus minimizing damage to expensive process equipment.

The Company’s 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 a vacuum. Many pipelines require cleaning while “on line” to help ensure the integrity of the pipeline and to maximize product throughput. The Company offers several techniques for pipeline cleaning. This includes 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 prepare structural analysis to determine if the pipeline is fit for its 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, refinery operations and petrochemical manufacturing use these products and services. 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 the customers 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. The Company’s field specialists, working with the rig crews, deploy completion tools in the well during the completion process.

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

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 the first quarter of 2005, the Company completed the construction of a well screen manufacturing facility in Houston, Texas. Well screens are sections of perforated pipe wrapped with wire that are placed in production tubing and are designed to prevent the flow of gravel into the producing wellbore. Well screens are critical to the success of wells in unconsolidated sandstone reservoirs and are integrated into the completion program (sand control, completion tools and well screens). Well screens are utilized primarily in unconsolidated sandstone reservoirs, the majority of which are located 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. These fluids are solids-free, and therefore, will not restrict oil and natural gas formations. In contrast, drilling mud, the fluid typically used during drilling and in some well completions, contains solids to achieve densities greater than water. These solids can restrict 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 used 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 at its own 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 pressure pumping customers. In recent months, the Company has experienced tightness in supply for certain types of cement and fracturing proppants but has been able to use alternatives with customer acceptance, and it is not expected to materially hinder operations.

Repair parts and maintenance items for pressure pumping equipment are held in inventory at levels that the Company believes will allow continued operations without significant downtime. 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 does not depend on any single source of supply for any materials; however, loss of one or more of our suppliers could disrupt operations.

Pressure pumping services use 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 allows 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 used in performing coiled tubing services are and will continue to be widely available from a number of manufacturers. Although there are only two principal manufacturers of the coiled tubing, the Company has not experienced any difficulty in obtaining coiled tubing in the past and does not anticipate difficulty in the foreseeable future.

Nitrogen is one of the principal materials used in the Company’s other oilfield services. The Company purchases nitrogen from several suppliers. The Company has experienced only intermittent tightness in supply or extended lead times in obtaining nitrogen and does not expect any chronic shortage of nitrogen in the foreseeable future.

Engineering and Support Services

The Company’s research and development department 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 laboratory 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, and 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 used to monitor both cement and stimulation job parameters. This software, combined with the Company’s internally developed monitoring hardware, allows for real-time job control and post-job analysis.

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

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

Completion Tools Engineering. The completions tools engineering group specializes in the designing, manufacturing and testing of completion tools. Since completion 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 raw materials, operating conditions and design specifications.

Manufacturing

The Company has three primary manufacturing facilities. In addition to its engineering facility, the Company’s research and technology center in Tomball, Texas also houses its main equipment and instrumentation manufacturing and assembly 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 completed the construction of a well screen manufacturing facility in Houston, Texas in the first 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 vendor.

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 80% of the worldwide pressure pumping services to the industry. Several smaller companies as well as a recent entrant, Weatherford International, Inc., compete with the Company in certain areas of the U.S. The Company also has competition from smaller companies internationally. The principal areas 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. The Company began offering these services in 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 precommissioning and leak detection services and one of the largest providers of pipeline inspection services. Our principal competitors in pipeline inspection are Pipeline Integrity International Ltd. (a division of General Electric), Tuboscope (a subsidiary of National Oilwell Varco) and H. Rosen Engineering GmbH. 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, Schlumberger Limited, Baker Hughes Incorporated and Weatherford International, Inc. The principal areas of competition are 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 2005, 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 is 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 1,323 in fiscal 2005, a 15% increase over the fiscal 2004 average U.S. rig count of 1,155. In fiscal 2004, the average U.S. rig count was 20% higher than the fiscal 2003 U.S. rig count average of 966. 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 48 countries which encompass 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, operating in approximately 48 countries provides some protection against volatility risk of individual countries. 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 1,311 in fiscal 2005. 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 in offshore Brazil. During fiscal 2005, the Company opened offices in Libya where it anticipates the start of operations during fiscal 2006.

The Company 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, inflation, governmental expropriation, currency exchange controls, political instability and other risks. The risk of currency exchange rate fluctuations and its impact on net income are mitigated by using natural hedges in which 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, 2005, the Company employed approximately 13,600 personnel around the world. Approximately 62% of the Company’s employees were employed outside the United States. The Company has experienced intermittent labor shortages in the North America markets, as these markets continue to experience expanding activity levels. As in the past, the Company has accommodated for these temporary shortages by increasing the number of contract personnel and contract services in order to meet customer requirements.

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 who contributed to the release of a “hazardous substance” into the environment. Certain disposal facilities owned by third parties but 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 the ultimate resolutions should not have a materially adverse effect on the Company’s results of operations or financial position.

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 uses technologies owned by third parties under various license arrangements, generally ranging from 10 to 20 years in duration, relating to certain products or methods for performing services. 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^TM, lightweight proppants (patented and patents pending). These low-density proppants produce greater propped fracture length and conductivity than is produced by conventional proppants and may be transported to the formations with lower polymer concentration gels than is required by conventional proppants.

Other stimulation technologies include the patented BJ Sandstone Acid^TM 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^TM, a relative permeability modifier, which was patented in 2001. It is a 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.

The Company has development leading technologies for its coiled tubing services. The patented Tornado^TM 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^TM gravel pack cleaning system is used in removing material restricting a gravel pack. During 2001 and 2002, the Company developed the LEGS^TM (lateral entry guidance system) tool for use with coiled tubing operations in horizontal wells. The LEGS^TM tool provides the technology to locate and successfully guide the coiled tubing into horizontal wells in order to perform coiled tubing workover operations.

During 2005, the Company continued to expand its portfolio of proprietary technologies and improve upon existing technologies. The Company continued developing and improving the InsulGel™ and Super InsulGel™ families of thermally insulated packer fluids for minimizing heat transfer from produced fluids. These fluids reduce heat loss through either conduction and convection mechanisms, allowing an improvement of heat retention and reducing or eliminating the need for insulating tubing. Proprietary additives to enhance the performance of fracturing and other systems, such as ScaleSorb^TM scale control agent to provide immediate and long-term pack protection from scale deposits, continue to be developed and introduced to the market.

The Company has also made advances in cementing technologies. LOTIS™ (Long-Term Isolation) cement engineering process allows the potential long-term stresses on the well to be analyzed, making it possible to design the correct cement formulation and evaluate the material properties of the set cement to ensure long-term

annular isolation. The proprietary IsoVison™ modeling program for calculating the direction and magnitude of induced stress in the cement sheath was also introduced. The IsoVision analysis enables the design of slurry formulations that offer cement properties precisely matched to the varied requirements of offshore and land operations.

Other Oilfield Services Research & Development

The Company has developed a broad line of completion tool systems for both 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^TM service tool packer. During 2001 and 2002, the Company successfully field-tested a composite drillable bridge plug, the Python^TM, 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.

During 2005, the Company successfully field tested the Multi-Zone Single Trip (MST) tool, which allows the operators to install multiple gravel packs in a well during a single trip. The MST also provides for frac packing each zone individually.

In 2005, the Company began designing and manufacturing a wide range of screens for soft rock completions in its new state-of-the-art manufacturing facility. Standard and heavy-duty wire wrapped screens, standard pre-packed wire wrapped screens, premium screens, and premium diffused bonded laminated screens are manufactured in this facility.

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, 2005, see Note 12 of the Notes to Consolidated Financial Statements.

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 may 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:

•

potential declines or increased volatility in oil and natural gas prices that would adversely affect our customers and the energy industry,

•

declines in drilling activity,

•

reduction in prices or demand for our products and services,

•

general global economic and business conditions,

•

the ability of the Organization of the Petroleum Exporting Countries (OPEC) to set and maintain production levels for oil,

•

the Company’s ability to successfully integrate acquisitions,

•

our ability to generate technological advances and compete on the basis of advanced technology,

•

delays in oil and natural gas activity permitting,

•

the potential for unexpected litigation or proceedings,

•

competition and consolidation in our businesses and

•

potentially higher prices for products used by the Company in its operations.

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:

•

in the pressure pumping, completion fluids, completion tools and casing and tubular services, during work performed on oil and natural gas wells,

•

in the production chemical business, as a result of use of the Company’s products in oil and natural gas wells and refineries, and

•

in the process and pipeline business, as a result of work performed by the Company at petrochemical plants as well as on pipelines.

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 Ongoing Investigations. In recent government actions, civil and criminal penalties and other sanctions have been imposed against several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls. The U.S. Department of Justice, the U.S. Securities and Exchange Commission (“SEC”) and other authorities have a broad range of civil and criminal sanctions they may seek to impose in these circumstances, including, but not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. We are in discussions with the Department of Justice and the SEC regarding our internal investigations and cannot currently predict the outcome of our investigations, when any of these matters will be resolved, or what, if any, actions may be taken by the Department of Justice, the SEC or other authorities or the effect the actions may have on our consolidated financial statements.

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:

•

limits on access to international markets,

•

unsettled political conditions, war, civil unrest, and hostilities in some petroleum-producing and consuming countries and regions where we operate or seek to operate,

•

declines in, or suspension of, activity by our customers in our areas of operations due to adverse local or regional economic, political and other conditions that affect drilling operations,

•

fluctuations and changes in currency exchange rates,

•

the impact of inflation,

•

governmental action such as expropriation of assets, and changes in general legislative and regulatory environments, exchange controls, global trade policies such as trade restrictions and embargoes imposed and international business, political and economic conditions and

•

the risk that events or actions taken by the Company or others as a result of its currently ongoing investigations (see “Management’s Discussion and Analysis—Investigations Regarding Misappropriation and Possible Illegal Payments.”) adversely affect the Company’s operations in the affected countries.

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:

•

evacuation of personnel and curtailment of services,

•

damage to offshore drilling rigs resulting in suspension of operations, and

•

loss of or damage to our equipment, inventory, and facilities.

Credit. If the Company’s credit rating is downgraded below investment grade, this 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 changes in environmental laws and other governmental regulations.

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 (“SEC”). Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically.

Executive Officers of the Registrant

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


Name	Age	Position with the Company	Office Held Since
J. W. Stewart	61	Chairman of the Board, President and Chief Executive Officer	1990
Mark Airola	47	Assistant General Counsel and Chief Compliance Officer	2003
Alasdair Buchanan	45	Vice President—Technology and Logistics	2005
Susan Douget	45	Director of Human Resources	2003
David Dunlap	44	Vice President and President—International Division	1995
Brian McCole	46	Controller	2002
Margaret B. Shannon	56	Vice President—General Counsel	1994
Jeffrey E. Smith	43	Treasurer	2002
T. M. Whichard	47	Vice President—Finance and Chief Financial Officer	2002
Kenneth A. Williams	55	Vice President and President—U.S./Mexico Division	1991

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.

Mr. Buchanan joined the Company in 1982 as a Trainee Engineer and was named Vice President—Technology and Logistics in 2005. He has previously served in numerous international Engineering and Operations positions, including most recently as Region Manager of the Europe Africa Region, a position he had held since 1999.

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

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

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

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

Mr. Williams joined the Company in 1973 and has since held various positions in the U.S. operations. Prior to being named Vice President—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 and began building a new corporate office during fiscal 2005. The office is expected to be completed in March 2006. Other 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, primarily serving pressure pumping services. 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 completed the construction of a well screen manufacturing facility in Houston, Texas in the first 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 and equipment 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.

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 (“Western”), Nowsco Well Service Ltd.

(“Nowsco”), 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.

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 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 Court has denied the Company’s motion requesting that the case be reinstated solely for the purpose of conducting a Markman hearing to construe the claims in the Halliburton patent. Irrespective of the outcome of the pending 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.

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 29, 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 were 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 was held on April 4, 2005, and the parties are awaiting a ruling. Great Lakes Chemical Corporation, which formerly 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 $5.6 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 and seeking damages. 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 defendants are all alleged to have been the Jones Act employers of these plaintiffs and/or manufactured, distributed or utilized products containing asbestos. The plaintiffs are in the process of completing data sheets specifying the companies they were employed by and the asbestos-containing products to which they were allegedly exposed. Through this process, approximately 20 plaintiffs have identified the Company or its predecessors as their employer. No products of the Company or its predecessors have been identified to date by any plaintiffs as having contained asbestos. Once the data sheet process is complete, we expect that the Company will be dismissed from any case where it is not identified as the employer. Only minimal medical information regarding the alleged asbestos-related disease suffered by the plaintiffs has been provided. 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 respond to these claims. In addition to the Jones Act cases, the Company has been named in a small number of additional asbestos cases. The allegations in these cases vary, but generally include claims that the Company provided some unspecified product or service which contained or utilized asbestos. Some of the allegations involve claims that the Company is the successor to the Byron Jackson Company. To date, the Company has been successful in obtaining dismissals of such cases without any payment in settlements or judgments, although some remain pending at the present time. The Company intends to defend itself vigorously in all of these cases 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.

U.S. Commerce Department Settlement Agreement

The Company entered into a Settlement Agreement dated July 7, 2005 with the U.S. Commerce Department’s Bureau of Industry and Security (“BIS”) regarding violations of certain export laws which occurred between 1999 and 2002. These violations relate to a total of 13 unlicensed shipments of chemical products made during this time frame. These products were used in the Company’s oilfield operations in China, Russia and Colombia, and contained chemical compounds as ingredients that are regulated under the Export Administration Regulations as precursors for weapons or drugs. While none of these products left the control of the Company or its subsidiaries, the concentration of the restricted chemical compounds in the products triggered the requirement for an export license when shipped from the United States. The Company detected these unlicensed shipments during a review of its export records and voluntarily reported the violations to the BIS. The Settlement Agreement required the payment of a fine by the Company in the amount of $142,450 and that the Company submit a self-audit of its export compliance program to the BIS no later than twenty four months following the entry of the Settlement Agreement.

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 $2.5 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.

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, 2005.

PART II

ITEM 5.

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

The Common Stock of the Company began trading on The New York Stock Exchange in July 1990 under the symbol “BJS”. At December 6, 2005, there were approximately 1,495 holders of record of the Company’s Common Stock.

The table below 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. On July 28, 2005 the Company’s Board of Directors approved a 2 for 1 stock split to be effected in the form of a stock dividend payable on September 1, 2005 to stockholders of record as of August 18, 2005. All share and share prices have been adjusted to reflect the stock prices on a post-split basis.


	Common Stock Price Range
	High		Low
Fiscal 2004
1^st Quarter	$	18.60	$	15.06
2^nd Quarter		22.89		17.43
3^rd Quarter		23.88		19.86
4^th Quarter		27.00		22.24
Fiscal 2005
1^stQuarter		27.00		22.48
2^nd Quarter		25.94		21.55
3^rd Quarter		27.10		23.74
4^th Quarter		36.39		26.48

From its initial public offering in 1990 until 2004, BJ Services did not pay any cash dividends to its stockholders. On July 22, 2004, the Company announced the initiation of a regular quarterly cash dividend. The Company paid cash dividends in the amount of $.04 per common share on a quarterly basis, totaling $51.9 million during fiscal 2005. On July 28, 2005 the Company’s Board of Directors approved a 25% increase in the quarterly cash dividend and declared a cash dividend of $.05 per common share payable on October 15, 2005 to shareholders of record on September 15, 2005, in the aggregate amount of $16.1 million. The Company anticipates paying cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2006. However, dividends are subject to approval of the Company’s Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

Information regarding equity compensation plans can be located in the section entitled “Equity Compensation Plan Information” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which sections are incorporated herein by reference.

At September 30, 2005, there were 347,510,648 shares of Common Stock issued and 323,410,991 shares outstanding. The Board of Directors has unanimously approved the charter amendment increasing the authorized number of shares of common stock from 380,000,000 shares to 980,000,000 shares, which requires stockholder approval. Additional information is available in the section entitled “Proposed Increase in Authorized Shares of Common Stock” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which sections are incorporated herein by reference.

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. The Company purchased 48,366,000 shares at a cost of $499.0 million through fiscal 2002. During fiscal 2005, the Company purchased a total of 3,982,000 shares at a cost of $98.4 million. There were no such repurchases in fiscal 2004 or fiscal 2003.

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-eighth 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, 2001, and 2005, one Right is associated with eight outstanding shares of common stock. The purchase price for the one-eighth of a Right associated with one share of common stock is effectively $65. 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.

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 for the period ended September 30, 2005 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.


	As of and For the Year Ended September 30,
	2005			2004			2003			2002⁽¹⁾⁽²⁾			2001
	(in thousands, except per share amounts)
Operating Data:
Revenue	$	3,243,186		$	2,600,986		$	2,142,877		$	1,865,796		$	2,233,520
Operating expenses, excluding goodwill amortization		2,606,127			2,162,601			1,849,636			1,602,906			1,683,602
Goodwill amortization		—			—			—			—			13,739
Operating income		637,059			438,385			293,241			262,890			536,179
Interest expense		(10,951	)		(16,389	)		(15,948	)		(8,979	)		(13,282	)
Interest income		11,281			6,073			2,141			2,008			2,567
Other income (expense), net⁽³⁾		15,958			92,668			(3,762	)		(3,225	)		3,717
Income tax expense		(200,305	)		(159,696	)		(87,495	)		(86,199	)		(179,922	)
Net income		453,042			361,041			188,177			166,495			349,259
Earnings per share⁽⁴⁾:
Basic		1.40			1.13			.60			.53			1.07
Diluted		1.38			1.10			.58			.52			1.05
Depreciation and amortization		136,861			125,668			120,213			104,915			104,969
Capital expenditures⁽⁵⁾		323,763			200,577			167,183			179,007			183,414

Financial Position Data (at end of period):
Property, net	$	1,086,932		$	913,713		$	850,340		$	798,956		$	676,445
Total assets		3,396,498			3,290,697			2,789,502			2,438,543			1,989,012
Long-term debt and capital leases, excluding current maturities		455			78,936			493,754			489,062			79,393
Stockholders’ equity		2,483,753			2,094,136			1,650,632			1,418,628			1,370,081
Cash dividends declared per common share⁽⁶⁾		.17			.04			—			—			—

⁽¹⁾	Includes the effect of the acquisition of OSCA, Inc. in May 2002 from the date of acquisition.

⁽²⁾	The Company ceased amortizing goodwill on October 1, 2001 in accordance with its adoption of Financial Accounting Standards Board Statement No. 142, “Goodwill and Other Intangible Assets”.

⁽³⁾

Includes Halliburton patent infringement award of $86.4 million (net of legal expenses) in fiscal 2004 and $12.2 million for the reversal of excess liabilities in the Asia Pacific region. Additionally, it includes $9.0 million in misappropriated funds from the Asia Pacific region repaid to the Company in fiscal 2005 and $9.5 million for the reversal of excess accrued liabilities in the Asia Pacific region. See Note 12 of the Notes to the Consolidated Financial Statements.

⁽⁴⁾	Earnings per share amounts have been restated for all periods presented to reflect the increased number of common shares outstanding resulting from the 2-for-1 stock splits effective May 31, 2001 and September 1, 2005.

⁽⁵⁾	Excluding acquisitions of businesses.

⁽⁶⁾

The Company paid cash dividends in the amount of $.04 per common share on a quarterly basis, totaling $51.9 million during fiscal 2005. The quarterly cash dividend was increased to $.05 per common share and a dividend was payable on October 15, 2005 to shareholders of record on September 15, 2005, in the aggregate amount of $16.1 million.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Investigations Regarding Misappropriation and Possible Illegal Payments

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 totaling approximately $9.0 million during a 30-month period ended April 2002. The misappropriations of approximately $9.0 million were repaid to the Company and the Region Controller’s employment was terminated. Although unauthorized, the misappropriations were an expense of the Company in the form of theft that were recorded in the Consolidated Statement of Operations in periods prior to April 2002. The $9.0 million repayment represents a gain contingency and was reflected in Other Income in the Consolidated Condensed Statement of Operations for the quarter ended December 31, 2004 in accordance with SFAS 5, Accounting for Contingencies.

Prior to filing its report on Form 10-K for fiscal 2004, the Company conducted a review of the Asia Pacific Region’s balance sheet and determined that net excess accrued liabilities had accumulated over a period of years which still existed at September 30, 2004 in the amount of $12.2 million. Based on a comprehensive analysis, the Company identified a further $9.5 million of excess accrued liabilities in the Asia Pacific Region, which were reversed in the fourth quarter of fiscal 2005. The following adjustments were recorded in accordance with GAAP and Company policy:


in millions	2005			2004
Gross reduction of other accrued liabilities	$	2.8		$	10.6
Adjustments of and reclassifications to balance sheet accounts		7.6			(7.8	)

Net reduction of excess accruals		10.4			2.8
(Addition) reduction of minority interest liability		(0.9	)		9.4

Net increase to income before tax		9.5			12.2
Income tax provision		(2.9	)		(.9	)

Total increase to net income	$	6.6		$	11.3

The net effect of these adjustments was reported in Other Income in the Consolidated Statement of Operations for the years ended September 30, 2005 and 2004.

The Company is continuing to investigate whether additional funds were misappropriated beyond the $9.0 million originally identified and investigate other possible inappropriate actions. To date, the Company has identified an additional $1.7 million that it believes was stolen by the former Region Controller. Although unauthorized, the additional $1.7 million of likely theft was an expense of the Company that was recorded in the Consolidated Statement of Operations in periods prior to April 2002. 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. The investigation, which is continuing, has found information indicating a significant likelihood that payments, which may have been illegal, were made to government officials in the Asia Pacific Region aggregating approximately $2.6 million over several years. The Company has voluntarily disclosed information found in the investigation to the U.S. Department of Justice (“DOJ”) and U.S. Securities and Exchange Commission (“SEC”) and is engaged in ongoing discussions with these authorities as they review the matter.

The Company and the special investigation by the Audit Committee are continuing to investigate other payments of approximately $10 million in the Asia Pacific Region (beyond those referenced above). In some cases, the Company has not yet been able to establish the legitimacy of the transactions reflected in the underlying documents and in other cases there are questions about the adequacy of the underlying documents to support the accounting entries. Such payments may prove to have been proper, but due to circumstances surrounding the payments, the Company continues to investigate to determine whether theft or other improprieties may have been involved. Such payments have been previously expensed, and therefore the Company believes that no additional expense is required to be recorded for such payments.

In connection with discussions regarding possible illegal payments in the Asia Pacific Region, U.S. government officials raised a question whether the Company had made illegal payments to a contractor or intermediary to obtain business in a country in Central Asia. The Audit Committee is investigating this question. The Company has voluntarily disclosed information found in the investigation to the DOJ and SEC and is engaged in ongoing discussions with these authorities as they review the matter.

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

As discussed in our Annual Report on Form 10-K for the period ended September 30, 2004, the misappropriations and related accounting adjustments in the Asia Pacific Region were possible because of certain internal control operating deficiencies. During fiscal 2002, the Company implemented policy changes worldwide for disbursements. In March 2005, the Company assigned a new Controller to the Asia Pacific region, and enhanced the Controller’s department. In addition, we have put in place Control and Process Improvement Managers at each of our six regional bases world-wide to document, enhance and test our control processes. The Company has also made several enhancements to its accounting policies and procedures. In 2005 the Company

adopted new policies and procedures for the retention of international commercial agents. The Company is still in the process of reviewing its control policies and procedures and may make further enhancements.

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 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:


	2005		% Change		2004		% Change		2003
Rig Count:⁽¹⁾
U.S.		1,323	15	%		1,155	20	%		966
International⁽²⁾		1,311	11	%		1,184	7	%		1,102
Commodity Prices (average):
Crude Oil (West Texas Intermediate)	$	53.69	44	%	$	37.16	22	%	$	30.36
Natural Gas (Henry Hub)	$	7.41	33	%	$	5.59	5	%	$	5.31

⁽¹⁾	Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Incorporated rig count information.

⁽²⁾	Includes Mexico average rig count of 111, 110 and 87 for the fiscal years ended September 30, 2005, 2004 and 2003, respectively.

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 1,323 in fiscal 2005.

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, operating in approximately 48 countries provides some protection against volatility risk of individual countries. 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 1,311 in fiscal 2005. During fiscal 2005, active international drilling rigs (excluding Canada) drilling activity averaged 894, compared to 818 rigs in fiscal 2004 and 761 rigs in fiscal 2003. Canadian drilling activity averaged 417 active drilling rigs in fiscal 2005, compared to 366 rigs in fiscal 2004 and 341 rigs in fiscal 2003.

Acquisitions

On November 26, 2003, the Company completed the acquisition of Cajun Tubular Services, Inc. (“Cajun”) for a total purchase price of $8.1 million (net of cash). Cajun, located in Lafayette, Louisiana, provides tubular running, testing and torque monitoring services to the Gulf of Mexico market. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

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.

These acquisitions resulted in total goodwill of $6.2 million. Pro forma financial information is not presented in this Annual Report on Form 10-K, as the acquisitions were not material to the Company.

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):


	2005			% Change		2004			% Change		2003
Consolidated revenue	$	3,243.2		25	%	$	2,601.0		21	%	$	2,142.9
Revenue by business segment:
U.S./Mexico Pressure Pumping		1,683.2		33	%		1,269.8		29	%		982.6
International Pressure Pumping		1,041.9		17	%		891.4		11	%		801.8
Other Oilfield Services		517.7		18	%		438.8		22	%		358.5
Corporate		.4					1.0					—

Consolidated operating income		637.1		45	%		438.4		50	%		293.2
Operating income/(loss) by business segment:
U.S./Mexico Pressure Pumping		524.9		56	%		337.0		77	%		190.3
International Pressure Pumping		135.8		49	%		91.4		1	%		90.7
Other Oilfield Services		67.6		25	%		54.0		8	%		49.9
Corporate		(91.3	)				(44.1	)				(37.7	)

Consolidated Revenue and Operating Income: Increased drilling activity and pricing improvement in the U.S. and Canada along with activity improvements in the Middle East and Latin America led to the increase in fiscal 2005 revenue compared to fiscal 2004. The increases experienced in fiscal 2005 revenue were slightly offset by revenue decreases in Mexico and for our stimulation vessel in the North Sea.

Fiscal 2005 operating income also benefited from the increased revenue described above, but was hindered by the decrease in activity for the stimulation vessel in the North Sea. For fiscal 2005, consolidated operating income margins improved to 19.6% from 16.9% reported in fiscal 2004.

For fiscal 2004, increased drilling activity in the U.S. and Canada, pricing improvement in the U.S. and improved revenue from all service lines in the Other Oilfield Services segment were the primary reasons for the increase in revenue 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.

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

U.S./Mexico Pressure Pumping Segment

Results for fiscal 2005 compared to fiscal 2004

Increased U.S. drilling activity of 15% from fiscal 2004 as well as improved pricing in the U.S. led the increase in revenue. As of September 30, 2005, approximately 60% of our customers were on the new U.S. price

book, which became effective on May 1, 2005. Declines in Mexico activity reduced revenue 36% for Mexico, which slightly offset the gains experienced in the U.S. The decrease in Mexico activity, specifically from the Burgos area, was caused by our primary customer in Mexico curtailing spending on our contract in that area.

The increases in revenue described above, coupled with labor efficiency gains, contributed to the increase in operating income. 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 2005 increased 11% compared to fiscal 2004, with revenue increasing 33%. Utilization of newer, more efficient and more modern equipment also contributed to the increase in operating income (see the “Business” section for information on the U.S. fleet recapitalization initiative). In addition, the pricing improvement described above directly increased operating income without any associated cost. As with revenue, the increase in U.S. operating income was slightly offset by the decrease in our Mexico operations described above.

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.

The increase in operating income was primarily due to the increases in revenue described above, coupled with labor efficiency gains. The headcount for fiscal 2004 increased 6% compared to fiscal 2003, with revenue increasing 29%.

Outlook

The Company recently issued a price book increase for its U.S. pressure pumping operations. The increase averages 11% above the previous price book in the U.S. and was effective November 1, 2005. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

Based on forecasted increase in rig activity and the price book increase discussed above, the Company expects revenue to increase 20-25% in fiscal 2006, compared to fiscal 2005. 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 approximately 10% in the U.S. during fiscal 2006.

International Pressure Pumping Segment

Results for fiscal 2005 compared to fiscal 2004

The following table summarizes the increase in revenue for fiscal 2005 compared to fiscal 2004 for each of the operating segments of International Pressure Pumping:


	% Change in Revenue
Europe/Africa	6	%
Middle East	39	%
Asia Pacific	2	%
Russia	17	%
Latin America	20	%
Canada	19	%

Canadian, Middle Eastern, and Latin American operations were the primary contributors to the revenue increase. Canadian revenue increased as a result of a 14% increase in activity and improved pricing. The

Company issued a new price book for its Canadian operation on June 1, 2005. The new price book averaged a 9% increase over the previous price book. Increased fracturing and coiled tubing activity in India and Saudi Arabia and well control work in Bangladesh were major contributions to the increase in the Middle East. Average drilling activity in Latin America increased 19% compared to fiscal 2004, primarily enhancing revenue in Argentina and Brazil. Revenue in Argentina was up appreciably as a result of increased stimulation and coiled tubing activity. North Sea activity gains in the U.K. and Norway were almost entirely offset by decreased stimulation vessel activity. Throughout fiscal 2005, our primary customer for the vessel experienced delays in its well delivery schedule, resulting in a 53% decline in revenue compared to fiscal 2004. Improvements in Thailand and Vietnam were mostly offset by declines in Malaysia. In Malaysia, major customers have reduced their drilling and workover programs leading to a 29% revenue decline. Russian revenue increased from the overall market increase.

Operating income increased as a result of the improved revenues as described above. Similar to the U.S./Mexico Pressure Pumping segment, labor efficiencies were achieved. The headcount for fiscal 2005 increased 5% compared to fiscal 2004, with revenue increasing 17%. These operating income increases were partially offset by lower activity levels with the Company’s stimulation vessel in the North Sea. Since there are significant fixed costs associated with operating the stimulation vessel, there was a decline in operating profit.

Results for fiscal 2004 compared to fiscal 2003

The following table summarizes the change in revenue for fiscal 2004 compared to fiscal 2003 for each of the operating segments of International Pressure Pumping:


	% Change in Revenue
Europe/Africa	(1	)%
Middle East	6	%
Asia Pacific	(4	)%
Russia	25	%
Latin America	5	%
Canada	31	%

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.

Outlook

The Company issued a price book increase for its Canadian pressure pumping operations. The increase averages 9% above the previous price book in Canada and was effective June 1, 2005. The degree of customer acceptance of the price book increase will depend on activity levels and competitive pressures.

Compared to levels experienced during fiscal 2005, the Company expects revenue in Canada to increase 20-25% and international revenue outside of Canada to increase 5-10% for fiscal 2006. The estimated increase is based on forecasted increase in rig activity and the price book increase discussed above.

Other Oilfield Services Segment

Results for fiscal 2005 compared to fiscal 2004

The following table summarizes the change in revenue for fiscal 2005 compared to fiscal 2004 for each of the operating segments of Other Oilfield Services:


	% Change in Revenue
Tubular Services	21	%
Process & Pipeline Services	14	%
Chemical Services	13	%
Completion Tools	5	%
Completion Fluids	37	%

Revenue from each service line within Other Oilfield Services increased during fiscal 2005. However, the increase in revenue from Completion Tools was minimal due to severe hurricane activity experienced in the Gulf of Mexico during the Company’s fourth fiscal quarter. This decrease was offset by increases in revenue internationally. Most of the revenue increase in Completion Fluids was as a result of increased product sales in the U.S., Mexico, and Norway. Tubular Services’ revenue benefited from increased activity in the North Sea and Asia Pacific.

Fiscal 2005 operating income margins were consistent with fiscal 2004 for all service lines. Operating income improved for the reasons described above; however, there were additional costs for worker’s compensation and write off of uncollectible accounts receivable.

Results for fiscal 2004 compared to fiscal 2003

The following table summarizes the change in revenue for fiscal 2004 compared to fiscal 2003 for each of the operating segments of Other Oilfield Services:


	% Change in Revenue
Tubular Services	51	%
Process & Pipeline Services	23	%
Chemical Services	7	%
Completion Tools	12	%
Completion Fluids	23	%

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 compared to prior years, many refineries deferred their maintenance shut-downs in 2003 until fiscal 2004. 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 primary 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.

Outlook

In fiscal 2006, we expect revenue from Other Oilfield Services to increase 5-10% from fiscal 2005, primarily attributable to expansion in international markets.

Other Expenses

Depreciation Expense: Depreciation expense is included in Cost of Sales and Services on the Consolidated Statement of Operations. For fiscal 2005, depreciation expense increased by $11.2 million, compared to fiscal 2004. For fiscal 2004, depreciation expense increased by $5.5 million, compared to fiscal 2003. These increases in depreciation expense are primarily a result of the Company’s increased capital spending levels.

Loss on Disposal of Assets: Rig count has experienced double digit growth over the last three years. As such, all of the Company’s equipment that can perform is currently working. As a result of year-end procedures, it was determined that the remaining equipment that was not able to operate would be written down to the fair value of the usable major components. The fair value of these assets was based on market prices for same, or similar assets. As a result, an $11.7 million impairment was recorded during the Company’s fourth fiscal quarter of 2005 and is reflected in the Corporate results.

The following table sets forth the Company’s other operating expenses as a percentage of revenue:


	2005		2004		2003
Research and engineering	1.7	%	1.8	%	1.9	%
Marketing expense	2.8	%	3.2	%	3.4	%
General and administrative expense	3.4	%	3.0	%	3.2	%

Research and engineering and marketing expenses: The aggregate of these expenses increased 13% for fiscal 2005, compared to fiscal 2004. As a percent of revenue, each of these expenses was relatively consistent with the same periods of the prior year.

General and administrative expenses: Legal and other costs of $6.2 million associated with the ongoing investigation in our Asia Pacific Region (see “Investigations Regarding Misappropriation and Possible Illegal Payments” above), as well as fees of $10.9 million related to preparations for our first year under Section 404 of the Sarbanes-Oxley Act, have led to increases in general and administrative expenses for fiscal 2005. In addition, due to increased activity levels, labor costs and incentive compensation costs have increased during fiscal 2005.

The following table shows interest income, interest expense, and other income (expense), net for fiscal 2005, 2004, and 2003 (in thousands):


	2005			2004			2003
Interest expense	$	(11.0	)	$	(16.4	)	$	(15.9	)
Interest income		11.3			6.1			2.1
Other income (expense)—net		16.0			92.7			(3.8	)

Interest Expense and Interest Income: Interest income increased for fiscal 2005 as a result of increases in average cash and cash equivalents. In April 2005, the Company redeemed the outstanding Convertible Senior Notes due 2022 for $422.4 million (see Note 5 of the Notes to the Consolidated Financial Statements). As a result, interest expense decreased for fiscal 2005.

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

Other (Expense) Income, net: Other Income increased during fiscal 2005 due to the Company recording a gain of $9.0 million relating to the recovery of misappropriated funds (see “Investigations Regarding Misappropriation and Possible Illegal Payments” above) in the first quarter. In addition, $9.5 million was recorded in the fourth quarter to reflect the reversal of excess accrued liabilities in the Asia Pacific region. For additional details of this account, see Note 12 of the Notes to the Consolidated Financial Statements.

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. For additional details of this account, see Note 12 of the Notes to the Consolidated Financial Statements.

Income Taxes: Consistent with fiscal 2004, the fiscal 2005 effective tax rate was 30.7%. The effective tax rate was 30.7% for fiscal 2004, down from 31.7% experienced in fiscal 2003. These rates vary primarily due to fluctuations in taxes from the mix of domestic versus foreign income.

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):


	2005			2004			2003
Cash flow from operations	$	545.7		$	528.6		$	320.0
Cash flow used in investing		(86.2	)		(443.6	)		(162.0	)
Cash flow provided by financing		(527.7	)		58.2			28.0
Effect of exchange rate changes on cash		—			3.9			6.9

Change in cash and cash equivalents	$	(68.2	)	$	147.1		$	192.9

Fiscal 2005

The Company’s working capital increased $136.8 million at September 30, 2005 compared to September 30, 2004. Accounts receivable increased $154.7 million, inventory increased $53.2 million, and accounts payable and accrued employee compensation increased $81.8 million and $26.9 million, respectively, primarily as a result of an increase in U.S. and Canadian activity. In April 2005, the Company redeemed the outstanding Convertible Senior notes for $422.4 million (see Note 5 of the Notes to the Consolidated Financial Statements) thereby reducing cash and cash equivalents and current debt. In addition, the outstanding unsecured 7% Series B Notes in the amount of $79.0 million were classified as current during fiscal 2005 (see Note 5 of the Notes to the Consolidated Financial Statements).

The cash flow provided by investing was primarily attributable to the Company’s investment in U.S. treasury notes maturing during 2005 in the amount of $229.8 million offset by capital expenditures of $323.8 million for fiscal 2005.

Cash flows used in financing were primarily the result of the redemption of all of the outstanding Convertible Senior Notes referred to above, repurchases of the Company’s common stock totaling $98.4 million and the payment of dividends in the amount of $51.9 million during fiscal 2005.

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 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. activity.

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 $.04 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.

Liquidity and Capital Resources

Cash flow from operations is expected to be our primary source of liquidity in fiscal 2006. Our sources of liquidity also include cash and cash equivalents of $356.5 million at September 30, 2005 and the available financing facilities listed below (in millions):


Financing Facility	Expiration	Borrowings at September 30, 2005	Available at September 30, 2005
Revolving Credit Facility	June 2009	None	$400.0
Discretionary	Various times within the next 12 months	$3.4	40.9

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, totaling $0.5 million for fiscal 2005. In addition, the Revolving Credit Facility charges a utilization 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 2005 to date or fiscal 2004. There were no outstanding borrowings under the Revolving Credit Facility at September 30, 2005 and 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. The Company is currently in compliance with all covenants imposed by the terms of the Revolving Credit Facility.

In addition to the Revolving Credit Facility, the Company had $44.3 million available in various unsecured, discretionary lines of credit at September 30, 2005, 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 $3.4 million and $3.8 million in outstanding borrowings under these lines of credit at September 30, 2005 and September 30, 2004, respectively.

Management believes that cash flow from operations combined with cash and cash equivalents, 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, 2005 and September 30, 2004, the Company had issued and outstanding $79.0 million of unsecured 7% Series B Notes due February 1, 2006, net of discount, which are classified as current at September 30, 2005 based on their maturity date. Based on the Company’s current liquidity, the Company has the ability to pay this debt with available cash upon maturity. However, the Company believes it could refinance the obligation if circumstances warrant.

On April 24, 2002 the Company sold Convertible Senior Notes due 2022 with a face value at maturity of $516.4 million (gross proceeds of $408.4 million). The notes were unsecured senior obligations that ranked 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. On March 25, 2005 the Company called for the redemption of all of its outstanding convertible senior notes. The redemption date was April 25, 2005, with an aggregate redemption price of $422.4 million. The redemption of the notes was funded with cash.

Cash Requirements

As described earlier, the Company’s unsecured 7% Series B Notes become due February 1, 2006. The Company currently has the ability to pay this debt with available cash upon maturity.

The Company anticipates capital expenditures to be approximately $450 million in fiscal 2006, compared to $324 million in fiscal 2005. The 2006 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. 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 adding new equipment, however much of the older equipment still remains in operations due to the increases in market activity in the U.S. During fiscal 2004, the Company expanded this U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment, and approximately 30% of this equipment has been replaced through fiscal 2005. Recapitalization of the Company’s pressure pumping equipment in Canada that began in fiscal 2005 is approximately 25% complete through fiscal 2005. The actual amount of fiscal 2006 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and the Company’s ability to execute its budgeted capital expenditures.

In fiscal 2006, the Company’s pension and postretirement funding requirements are anticipated to be approximately $7.8 million.

The Company anticipates paying cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2006. Based on the shares outstanding on September 30, 2005, the aggregate annual amount would be $64.7 million. However, dividends are subject to approval of the Company’s Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

The Company expects that cash and cash equivalents and cash flow from operations will generate sufficient cash to fund all of the cash requirements described above.

The following table summarizes the Company’s contractual cash obligations as of September 30, 2005 (in thousands):


Contractual Cash Obligations	Total		Less than 1 year		1-3 Years		4-5 Years		After 5 Years
Long term and short term debt⁽¹⁾	$	78,984	$	78,984	$	—	$	—	$	—
Interest on long term debt and capital leases		2,832		2,797		35		—		—
Capital lease obligations		455		130		325		—		—
Operating leases		107,641		38,755		37,238		18,897		12,751
Equipment financing arrangements⁽²⁾		146,675		23,919		47,615		43,141		32,000
Purchase obligations⁽³⁾		144,827		144,447		380		—		—
Other long-term liabilities⁽⁴⁾		76,440		6,726		228		96		69,390

Total contractual cash obligations	$	557,854	$	295,758	$	85,821	$	62,134	$	114,141

⁽¹⁾	Net of original issue discounts.

⁽²⁾

As discussed below, the Company has the option, but not the obligation, to purchase the pumping service equipment in these two partnerships for approximately $27 million and $32 million in 2009 and 2010, respectively. Currently, the Company expects to purchase the pumping service equipment and has therefore included it in the table above.

⁽³⁾	Includes agreements to purchase goods or services that have been approved and that specify all significant terms (pricing, quantity and timing). Company policy does not require a purchase order to be completed for items that are under $200 and are for miscellaneous items, such as office supplies.

⁽⁴⁾

Includes expected cash payments for long-term liabilities reflected in the consolidated balance sheet where the amounts and timing of the payment are known. Amounts include: Asset retirement obligations, known pension funding requirements, post-retirement benefit obligation, environmental accruals and other miscellaneous long-term obligations. Amounts exclude: Deferred gains (see “Off Balance Sheet Transactions” below), pension obligations in which funding requirements are uncertain and long-term contingent liabilities.

The Company expects that cash and cash equivalents and cash flow from operations will generate sufficient cash flow to fund all of the cash requirements described above.

Off Balance Sheet Transactions

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 $22.1 million and $26.6 million as of September 30, 2005 and September 30, 2004, 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 April 2005 and 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 $1.1 million and $3.3 million, respectively. In October 2005, the Company received another partnership approval to substitute certain pumping services equipment, further reducing the deferred gain by $1.4 million. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. Currently, the Company expects to purchase the pumping service equipment in 2010.

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 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 “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. 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 $0.3 million and $0.4 million as of September 30, 2005 and September 30, 2004, 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. Currently, the Company expects to purchase the pumping service equipment in 2009.

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 and do not represent a financial obligation of the Company. 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, 2005 (in thousands):


			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby Letters of Credit	$	28,994	$	28,990	$	4	$	—	$	—
Guarantees		204,302		154,307		37,506		9,992		2,497

Total Other Commercial Commitments	$	233,296	$	183,297	$	37,510	$	9,992	$	2,497

Critical Accounting Policies

For an accounting policy to be deemed critical, the accounting policy must first include an estimate that requires a company to make assumptions about matters that are highly uncertain at the time the accounting estimate is made. Second, different estimates that the company reasonably could have used for the accounting estimate in the current period, or changes in the accounting estimate that are reasonably likely to occur from period to period, must have a material impact on the presentation of the company’s financial condition or results of operations.

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

Goodwill: 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 $885.2 million goodwill balance at September 30, 2005. 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 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 2006, the Company will have a pension and postretirement funding requirement of $7.8 million. We expect to fund this amount with cash flows from operating activities. See Note 9 of the Notes to Consolidated Financial Statements for more information on the Company’s pension plans.

Income Taxes: The effective income tax rates were 30.7%, 30.7%, and 31.7% for the years ended September 30, 2005, 2004, and 2003, 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. Our tax filings for various periods are subjected to audit by tax authorities in the jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we accrue income taxes where we consider it

probable that the taxes ultimately payable will exceed those amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies.

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 Notes to 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 May 2005, the FASB issued SFAS No. 154 (“SFAS 154”), Accounting Changes and Error Corrections. This is a replacement of APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. Under SFAS 154, all voluntary changes in accounting principle as well as changes pursuant to accounting pronouncements that do not include specific transition requirements, must be applied retrospectively to prior periods’ financial statements. Retrospective application requires the cumulative effect of the change be reflected in the carrying value of assets and liabilities as of the first period presented and the offsetting adjustments are recorded to beginning retained earnings. Each period presented must be adjusted to reflect the period specific effects of applying the change. Also, under the new statement, a change in accounting estimate continues to be accounted for in the period of change and in future periods if necessary. Corrections of errors should continue to be reported by restating prior period financial statements as of the beginning of the first period presented, if material. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company will adopt SFAS 154 on October 1, 2006. Adoption will not have a material impact on the Company’s financial position and results of operations, since SFAS 154 is to be applied prospectively.

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 (“SFAS 123”), and supersedes APB No. 25, Accounting for Stock Issued to Employees. Through September 30, 2005, the Company has not recorded compensation expense for its stock purchase plan and stock option plan. 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 October 1, 2005 and the Company will adopt SFAS 123(R) using the modified prospective method.

Under the modified prospective method the Company will recognize expense beginning October 1, 2005 on any unvested awards granted prior to the adoption date of October 1, 2005 over the remaining vesting period of the awards. New awards granted after the adoption date will be expensed over the vesting period of the award. The Company currently uses a Black-Scholes option pricing model for disclosures of stock-based compensation information and plans on continuing to use this model under SFAS 123(R) in determining the expense for awards under the stock option plan and the stock purchase plan. The Company has historically expensed the fair value of the awards granted from its stock incentive plan. Adoption of SFAS 123(R) will require the Company to utilize a binomial model to value the stock incentive plan awards. We do not anticipate the valuation methodology required under SFAS 123(R) to materially change the compensation expense associated with these awards the Company has historically recognized in the consolidated statement of operations. The following table summarizes the impact of the adoption of SFAS 123(R) for these plans:


	Fiscal 2006		Fiscal 2007		Fiscal 2008
	(in millions, pre-tax)
Plans not currently expensed:
Stock Option Plan
Previously unvested grants	$	8.8	$	4.8	$	0.6
Estimated future grants		4.3		8.6		12.9
Stock Purchase Plan (estimate)		3.2		3.2		3.2

Additional Expense Under SFAS 123(R)		16.3		16.6		16.7

Plans currently expensed:
Stock Incentive Plan
Previously unvested grants		7.9		4.2		—
Estimated future grants		4.2		8.3		12.5

		12.1		12.5		12.5
Director Stock Awards
Previously unvested grants		0.5		0.1		—
Estimated future grants		0.5		0.9		1.0

		1.0		1.0		1.0

Total Estimated Expense	$	29.4	$	30.1	$	30.2

Estimates of future grants in the table above are based on the level of grants awarded during fiscal 2005. The actual number of awards, or the types of awards granted may change. With respect to the Consolidated Statement of Financial Position, this will increase unearned compensation by approximately $40 million and will have an equally offsetting decrease in capital in excess of par in stockholders’ equity. For more information regarding these plans, see Note 13 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 Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010. Under the guidance in FASB Staff Position No. 109-1, Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, the deduction will be treated as a “special deduction” as described in FASB Statement No. 109. As such, the special deduction has no effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on our tax return. We do not expect that this deduction will have a material impact on our effective tax rate in future years. The Act is applicable to the Company beginning October 1, 2005.

which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109-2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. The Company is considering the possibility of remitting dividends in excess of $20 million and perhaps materially in excess of $20 million in its next fiscal year to claim the benefits of this new provision. Furthermore, the Company believes that any residual U.S. tax liability from this possible repatriation would be fully offset with excess foreign tax credits of the Company.

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 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. Any non-GAAP financial measures used by the Company are posted on the Company’s website at www.bjservices.com.

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 in statements described as “Outlook” and by their use of terms and phrases such as “expect,” “estimate,” “project,” “forecast,” “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:

•

fluctuating prices of crude oil and natural gas,

•

conditions in the oil and natural gas industry, including drilling activity,

•

reduction in prices or demand for our products and services and level of acceptance of price book increases in our markets,

•

general global economic and business conditions,

•

international political instability, security conditions, hostilities, and declines in customer activity due to adverse local and regional conditions,

•

the Company’s ability to expand its products and services (including those it acquires) into new geographic markets,

•

our ability to generate technological advances and compete on the basis of advanced technology,

•

risks from operating hazards such as fire, explosion, blowouts and oil spills,

•

litigation for which insurance and customer agreements do not provide protection,

•

adverse consequences that may be found in or result from our ongoing internal investigations, including potential financial and business consequences and governmental actions, proceedings, charges or penalties,

•

changes in currency exchange rates,

•

severe weather conditions, including hurricanes, that affect conditions in the oil and natural gas industry,

•

the business opportunities that may be presented to and pursued by the Company,

•

competition and consolidation in the Company’s business,

•

changes in law or regulations and other factors, many of which are beyond the control of the Company, and

•

risks from ongoing investigations.

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

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, 2005 rates, the Company’s combined interest expense to third parties would increase by a total of $2 thousand each month in which such increase continued. At September 30, 2005, the Company had issued fixed-rate debt of $79.0 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 $147 thousand if interest rates were to decline by 10% from their rates at September 30, 2005.

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, 2005. 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, 2005. 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.


	Expected Maturity Dates									Fair Value
	Expected Maturity Dates									Fair Value
	2006		2007	2008	2009	2010	Thereafter	Total		9/30/05
SHORT-TERM BORROWINGS

Bank borrowings; U.S. $ denominated	$	3,390						$	3,390	$	3,390
Average variable interest rate—7.75% at September 30, 2005

LONG-TERM BORROWINGS
7% Series B Notes—U.S. $ denominated
Fixed interest rate—7%		78,984							78,984		79,637

Total	$	82,374	—	—	—	—	—	$	82,374	$	83,027

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined by the Securities and Exchange Act of 1934 Rule 13a-15(f). The Company’s internal controls were designed to provide reasonable assurance as to the reliability of our financial statements for external purposes in accordance with accounting principles generally accepted in the U.S.

Internal control over financial reporting has inherent limitations and may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance, not absolute, assurance with respect to the financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, management has evaluated the effectiveness of the Company’s internal control over financial reporting as of September 30, 2005 as required by the Securities and Exchange Act of 1934 Rule 13a-15(c). In making its assessment, management has utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Management concluded that based on its evaluation, the company’s internal control over financial reporting was effective as of September 30, 2005.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.



/S/ J.W. STEWART				/S/ T.M. WHICHARD
J.W. Stewart				T.M. Whichard
President and Chief Executive Officer				Vice President and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Stockholders of BJ Services Company:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that BJ Services Company and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment of the effectiveness of internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of September 30, 2005, is fairly stated, in all material respects based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also, in our opinion, the Company maintained in all material respects, effective internal control over financial reporting as of September 30, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended September 30, 2005 of the Company and our report dated December 14, 2005 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

December 14, 2005

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, 2005 and 2004, 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, 2005. Our audits also included the financial statement schedule listed in the Index 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of September 30, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 14, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

December 14, 2005

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS


	Year Ended September 30,
	2005			2004			2003
	(in thousands, except per share amounts)
Revenue	$	3,243,186		$	2,600,986		$	2,142,877
Operating expenses:
Cost of sales and services		2,334,198			1,951,022			1,665,545
Research and engineering		54,197			47,287			40,810
Marketing		92,255			82,105			73,665
General and administrative		111,285			78,978			69,449
Loss on long-lived assets		14,192			3,209			167

Total operating expenses		2,606,127			2,162,601			1,849,636

Operating income		637,059			438,385			293,241
Interest expense		(10,951	)		(16,389	)		(15,948	)
Interest income		11,281			6,073			2,141
Other (expense) income, net		15,958			92,668			(3,762	)

Income before income taxes		653,347			520,737			275,672
Income tax expense		200,305			159,696			87,495

Net income	$	453,042		$	361,041		$	188,177

Earnings Per Share:
Basic	$	1.40		$	1.13		$	.60
Diluted	$	1.38		$	1.10		$	.58
Weighted-Average Shares Outstanding:
Basic		323,763			320,358			315,886
Diluted		329,115			326,828			322,514

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

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

ASSETS


	September 30,
	2005		2004
	(in thousands)
Current Assets:
Cash and cash equivalents	$	356,508	$	424,725
Short-term investments		—		229,930
Receivables, less allowance for doubtful accounts:
2005, $13,938; 2004, $9,010		695,359		544,946
Inventories:
Products		151,641		125,174
Work-in-process		7,545		2,656
Parts		75,905		55,040

Total inventories		235,091		182,870
Deferred income taxes		16,107		12,002
Prepaid expenses		21,245		20,849
Other current assets		10,161		9,635

Total current assets		1,334,471		1,424,957
Property:
Land		17,339		15,605
Buildings and other		269,191		250,361
Machinery and equipment		1,712,366		1,490,427

Total property		1,998,896		1,756,393
Less accumulated depreciation		911,964		842,680

Property, net		1,086,932		913,713
Goodwill		885,212		885,905
Deferred income taxes		24,140		23,250
Investments and other assets		65,743		42,872

Total assets	$	3,396,498	$	3,290,697

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

LIABILITIES AND STOCKHOLDERS’ EQUITY


	September 30,
	2005			2004
	(in thousands)
Current Liabilities:
Accounts payable, trade	$	326,632		$	247,230
Short-term borrowings		3,390			3,754
Current portion of long-term debt		78,984			419,585
Accrued employee compensation and benefits		104,962			78,049
Income taxes		36,568			39,037
Deferred income taxes		197			1,234
Taxes other than income		22,679			23,766
Accrued insurance		19,343			14,797
Other accrued liabilities		91,038			83,673

Total current liabilities		683,793			911,125
Long-term debt		—			78,936
Deferred income taxes		64,613			47,798
Accrued postretirement benefits		48,561			43,012
Other long-term liabilities		115,778			115,690
Commitments and contingencies (Note 10)
Stockholders’ Equity:
Preferred stock (authorized 5,000,000 shares, none issued)
Common stock, $.10 par value (authorized 380,000,000 shares; 347,510,648 shares issued and 323,410,991 shares outstanding in 2005; 347,510,648 shares issued and 323,737,678 shares outstanding in 2004)		34,752			34,752
Capital in excess of par		1,016,333			994,724
Retained earnings		1,739,157			1,340,939
Accumulated other comprehensive income (loss)		24,371			(908	)
Unearned compensation		(9,195	)		(6,961	)
Treasury stock, at cost (2005 – 24,099,657 shares; 2004 – 23,772,970 shares)		(321,665	)		(268,410	)

Total stockholders’ equity		2,483,753			2,094,136

Total liabilities and stockholders’ equity	$	3,396,498		$	3,290,697

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

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND

OTHER COMPREHENSIVE INCOME

(in thousands)


	Common Stock Shares		Common Stock		Capital In Excess of Par			Treasury Stock			Unearned Compensation			Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance, September 30, 2002	313,590		$	34,752	$	965,550		$	(382,271	)	$	(926	)	$	831,396		$	(29,873	)	$	1,418,628
Comprehensive income:
Net income															188,177
Other comprehensive income, net of tax:
Cumulative translation adjustments																		21,456
Minimum pension liability adjustment																		(1,230	)
Comprehensive income																					208,403
Reissuance of treasury stock for:
Stock option plan	1,410								15,828						(5,732	)					10,096
Stock purchase plan	1,318								14,862						(4,892	)					9,970
Stock incentive plan	294					(3,812	)		3,304						507						(1	)
Recognition of unearned compensation												1,108									1,108
Revaluation of stock incentive plan awards						182						(182	)								—
Tax benefit from exercise of options						2,428															2,428

Balance, September 30, 2003	316,612		$	34,752	$	964,348		$	(348,277	)	$	—		$	1,009,456		$	(9,647	)	$	1,650,632
Comprehensive income:
Net income															361,041
Other comprehensive income, net of tax:
Cumulative translation adjustments																		10,468
Minimum pension liability adjustment																		(1,729	)
Comprehensive income																					369,780
Dividend declared															(12,935	)					(12,935	)
Reissuance of treasury stock for:
Stock option plan	5,946								66,566						(17,304	)					49,262
Stock purchase plan	990								11,157						(217	)					10,940
Stock incentive plan	190					(3,103	)		2,144						898						(61	)
Stock incentive plan grant						7,273						(7,273	)								—
Recognition of unearned compensation												3,772									3,772
Revaluation of stock incentive plan awards						3,460						(3,460	)								—
Tax benefit from exercise of options						22,746															22,746

Balance, September 30, 2004	323,738		$	34,752	$	994,724		$	(268,410	)	$	(6,961	)	$	1,340,939		$	(908	)	$	2,094,136
Comprehensive income:
Net income															453,042
Other comprehensive income, net of tax:
Cumulative translation adjustments																		11,482
Minimum pension liability adjustment																		13,797
Comprehensive income																					478,321
Dividend declared															(55,005	)					(55,005	)
Treasury stock purchase	(3,982	)							(98,360	)											(98,360	)
Reissuance of treasury stock for:
Stock option plan	2,809								35,461						(2,447	)					33,014
Stock purchase plan	836								9,523						2,628						12,151
Stock incentive plan																					—
Director stock award	10					(121	)		121												—
Stock incentive plan grant						6,468						(6,468	)								—
Director stock award grant expense						874															874
Recognition of unearned compensation												7,807									7,807
Revaluation of stock incentive plan awards						3,573						(3,573	)								—
Tax benefit from exercise of options						10,815															10,815

Balance, September 30, 2005	323,411		$	34,752	$	1,016,333		$	(321,665	)	$	(9,195	)	$	1,739,157		$	24,371		$	2,483,753

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

BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS


	Year Ended September 30,
	2005			2004			2003
	(in thousands)
Cash flows from operating activities:
Net income	$	453,042		$	361,041		$	188,177
Adjustments to reconcile net income to cash provided from operating activities:
Depreciation		136,861			125,668			120,213
Net loss on long-lived assets		14,192			3,209			167
Recognition of unearned compensation		8,681			3,772			1,108
Deferred income tax expense		(7,111	)		109,775			29,508
Minority interest expense		3,725			2,286			5,080
Changes in:
Receivables		(154,677	)		(78,042	)		(110,786	)
Accounts payable, trade		81,756			31,509			56,415
Inventories		(53,161	)		(20,975	)		(4,446	)
Employee compensation and benefits		26,913			8,844			9,825
Current income tax		(7,611	)		(31,509	)		49,849
Other current assets and liabilities		11,477			(6,834	)		8,591
Other, net		31,618			19,863			(33,737	)

Net cash flows provided from operating activities		545,705			528,607			319,964

Cash flows from investing activities:
Property additions		(323,763	)		(200,577	)		(167,183	)
Proceeds from disposal of assets		7,834			2,149			5,184
Proceeds (purchases) of U.S. Treasury securities		229,774			(229,930	)		—
Acquisitions of businesses, net of cash acquired		—			(15,337	)		—

Net cash used for investing activities		(86,155	)		(443,695	)		(161,999	)

Cash flows from financing activities:
Proceeds from exercise of stock options and stock purchase plan		45,165			61,413			21,263
Purchase of treasury stock		(98,360	)		—			—
(Repayment) proceeds of long-term debt		(422,369	)		—			4,692
(Repayment) proceeds of short-term borrowings, net		(364	)		(2,134	)		2,110
Dividends paid to shareholders		(51,855	)		—			—
Debt issuance costs		—			(1,042	)		—

Net cash flows provided from/(used in) financing activities		(527,783	)		58,237			28,065

Effect of exchange rate changes on cash		16			3,910			6,909

(Decrease) increase in cash and cash equivalents		(68,217	)		147,059			192,939
Cash and cash equivalents at beginning of year		424,725			277,666			84,727

Cash and cash equivalents at end of year	$	356,508		$	424,725		$	277,666

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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements

1. Business and Basis of Presentation

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 worldwide provider of pressure pumping and other oilfield services for the petroleum industry. The Company’s pressure pumping services consist of cementing and stimulation services used in the completion of new oil and natural gas wells and in remedial work on existing wells, both onshore and offshore. Other oilfield services include completion tools, completion fluids and casing and tubular services provided to the oil and natural gas exploration and production industry, commissioning and inspection services provided to refineries, pipelines and offshore platforms, and production chemical services.

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

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

Share and earnings per share amounts have been restated for all periods presented to reflect the increased number of common shares outstanding resulting from the 2-for-1 stock split payable on September 1, 2005 to stockholders of record as of August 18, 2005.

Certain amounts for 2004 and 2003 have been reclassified in the accompanying consolidated financial statements to conform to the current year presentation.

2. Summary of Significant Accounting Policies

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

Short-term investments: Highly liquid investments with maturities of one year or less at the time of purchase are classified as short-term investments. The Company accounts for these short-term investments in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. These short-term investments are being held to maturity and are recorded at amortized cost. For purposes of the Consolidated Statement of Cash Flows, the Company does not consider short-term investments to be cash and cash equivalents because they generally have original maturities in excess of three months.

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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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

Property: Property is stated at cost less amounts provided for permanent impairments and includes capitalized interest of $1.2 million, $0.8 million and $0.6 million for the years ended September 30, 2005, 2004 and 2003, respectively, on funds borrowed to finance the construction of capital additions. Depreciation is generally provided using the straight-line method over the estimated useful lives of individual items. Leasehold improvements are amortized on a straight-line basis over the shorter of their estimated useful lives or the lease terms. The estimated useful lives are 10 to 30 years for buildings and leasehold improvements and range from 3 to 12 years for machinery and equipment. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. Additionally, the carrying values of these assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future cash flows. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. The amount of the impairment, if any, is the amount by which the net book value of the assets exceed fair value. Fair value determination requires the Company to make long-term forecasts of its future revenue and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Rig count has experienced double digit growth over the last three years. As such, all of the Company’s equipment that can perform is currently working. As a result of year-end procedures, it was determined that the remaining equipment that was not able to operate would be written down to the fair value of the usable major components. The fair value for these assets was based on market prices for same, or similar assets. As a result, an $11.7 million impairment was recorded during the Company’s fourth fiscal quarter of 2005 and is reflected in the Corporate results.

Intangible assets: Goodwill represents the excess of cost over the fair value of the net assets of companies acquired in purchase transactions. The Company accounts for goodwill in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets which requires goodwill to be reviewed for possible impairment on an annual basis, or if circumstances indicate that an impairment may exist. The Company performed its annual evaluation as of September 30 and concluded that an impairment adjustment was not necessary to the Company’s $885.2 million and $885.9 million net goodwill balance at September 30, 2005 and 2004, respectively. The changes in the carrying amount of goodwill by reporting unit for the year ended September 30, 2005, are as follows (in thousands):


	U.S./Mexico Pressure Pumping Services			International Pressure Pumping Services		Chemical Services		Process and Pipeline Services		Casing and Tubular Services		Completion Tools Services		Completion Fluids Services		Total
Balance 9/30/03	$	274,058		$	371,324	$	10,726	$	22,272	$	8,905	$	112,235	$	80,190	$	879,710

Acquisitions		—			—		—		—		6,195		—		—		6,195

Balance 9/30/04	$	274,058		$	371,324	$	10,726	$	22,272	$	15,100	$	112,235	$	80,190	$	885,905

Reversal of taxes		(2,277	)		1,584		—		—		—		—		—		(693	)

Balance 9/30/05	$	271,781		$	372,908	$	10,726	$	22,272	$	15,100	$	112,235	$	80,190	$	885,212

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

During fiscal 2005, goodwill was reduced by $0.7 million in connection with the resolution of certain tax uncertainties relating to prior acquisitions. Under EITF 93-7, Uncertainties Related to Income Taxes in a Purchase Business Combination, the resolution of these tax uncertainties is treated as an adjustment of the goodwill originally recorded in the acquisition.

Technology based intangible assets are being amortized on a straight-line basis ranging from 5-20 years, with the weighted average amortization period being 13.6 years. Technology based intangible assets net of accumulated amortization were $8.2 million and $4.3 million at September 30, 2005 and 2004, respectively. Amortization for the three years ended September 30, 2005, 2004 and 2003 was $0.5 million, $0.3 million and $0.2 million, respectively. The Company utilizes undiscounted estimated cash flows to evaluate any possible impairment of intangible assets. If such cash flows are less than the net carrying value of the intangible assets the Company records an impairment loss equal to the difference in discounted estimated cash flows and the net carrying value. The discount rate utilized is based on market factors at the time the loss is determined.

Income Taxes: The Company provides for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes. This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. This calculation requires the Company to make certain estimates about our future operations. Changes in state, federal and foreign tax laws as well as changes in our financial condition could affect these estimates. The Company records a valuation allowance to reduce its deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will expire before realization of the benefit. We consider all available evidence, both positive and negative, to determine whether a valuation allowance is needed. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character within the carryback or carryforward period set forth under the applicable tax law. Our tax filings for various periods are subjected to audit by tax authorities in the jurisdictions where we conduct business. These audits may result in assessments of additional taxes that are resolved with the authorities or potentially through the courts. Resolution of these situations inevitably includes some degree of uncertainty; accordingly, we provide taxes only for the amounts we believe will ultimately result from these proceedings. In addition to the aforementioned assessments that have been received from various taxing authorities, we provide for taxes in certain situations where assessments have not been received. In those situations, we accrue income taxes where we consider it probable that the taxes ultimately payable will exceed those amounts reflected in filed tax returns; accordingly, taxes are provided in those situations under the guidance in Statement of Financial Accounting Standards (“SFAS”) No. 5, Accounting for Contingencies.

Self Insurance Accruals: The Company is self-insured for certain losses relating to workers’ compensation, general liability, property damage and employee medical benefits for claims filed and claims incurred but not reported. The Company’s liability is based primarily on an actuarial undiscounted basis using individual case-based valuations and statistical analysis and is based upon judgment and historical experience; however, the final cost of many of these claims may not be known for five years or longer. Management reviews the reserve on a quarterly basis. Changes in claims experience, health care costs, etc. could affect these estimates.

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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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

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

Revenue Recognition: The Company’s revenue is composed of product sales, rental, service and other revenue. Products, rentals, and services are generally sold based on fixed or determinable priced purchase orders or contracts with the customer and do not include the right of return. The Company recognizes revenue from product sales when title passes to the customer, the customer assumes risks and rewards of ownership, and collectibility is reasonably assured. Rental, service and other revenue is recognized when the services are provided and collectibility is reasonably assured.

Research and development expenditures: Research and development expenditures are expensed as incurred.

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

Foreign currency translation: The Company’s functional currency is primarily the U.S. dollar. Gains and losses resulting from financial statement translation of foreign operations where a foreign currency is the functional currency are included as a separate component of stockholders’ equity. The Company’s operations in Canada and Hungary use their respective local currencies as the functional currency.

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

Employee stock-based compensation: Under SFAS No. 123 Accounting for Stock-Based Compensation, the Company is permitted to either record expenses for stock options and other stock-based employee compensation plans based on their fair value at the date of grant or to continue to apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and recognize compensation expense, if any, based on the intrinsic value of the equity instruments at the measurement dates. The Company elected to continue

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

following APB 25; therefore, no compensation expense has been recognized for the stock purchase plan and the stock option plan because the exercise prices of employee stock options equal the market prices of the underlying stock on the dates of grant. The Company expenses the fair value of the awards granted from its stock incentive plan and restricted stock awards. As discussed below, SFAS 123(R) is effective for the Company as of October 1, 2005.

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


	2005			2004			2003
Net income, as reported	$	453,042		$	361,041		$	188,177
Add: total stock-based employee compensation expense included in reported net income, net of tax		8,681			3,772			1,108
Less: total stock-based employee compensation expense determined under SFAS 123 for all awards, net of tax⁽¹⁾		(17,582	)		(17,714	)		(16,475	)

Net income, pro forma	$	444,141		$	347,099		$	172,810

Earnings per share:
Basic, as reported	$	1.40		$	1.13		$	.60
Basic, pro forma	$	1.37		$	1.08		$	.55
Diluted, as reported	$	1.38		$	1.10		$	.58
Diluted, pro forma	$	1.35		$	1.06		$	.54

⁽¹⁾

In October and November 2001, the Company granted approximately 100% more stock options than is typically granted, and therefore only a minimal amount was issued in the subsequent year. Given the three-year vesting schedule of these awards, stock-based compensation expense was higher in fiscal 2002, 2003 and 2004.

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


	2005			2004			2003
Stock Option Plan
Expected life (years)		4.7			5.0			4.9
Interest rate		3.6	%		3.7	%		3.2	%
Volatility		30.4	%		36.8	%		44.4	%
Dividend yield		0.7	%		—			—
Weighted-average fair value per share at grant date	$	6.99		$	6.07		$	7.04


	2005			2004			2003
Stock Purchase Plan
Expected life (years)		1.0			1.0			1.0
Interest rate		4.1	%		2.2	%		1.0	%
Volatility		16.4	%		15.8	%		19.2	%
Dividend yield		0.6	%		—			—
Weighted-average fair value per share at grant date	$	5.49		$	6.94		$	4.82

The Company calculated its volatility using historical daily, weekly and monthly price intervals to generate a reasonable range of expected future volatility, and used a factor at the low end of the range in accordance with SFAS 123.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

New accounting pronouncements: In May 2005, the FASB issued SFAS No. 154 (“SFAS 154”), Accounting Changes and Error Corrections. This is a replacement of APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. Under SFAS 154, all voluntary changes in accounting principle as well as changes pursuant to accounting pronouncements that do not include specific transition requirements, must be applied retrospectively to prior periods’ financial statements. Retrospective application requires the cumulative effect of the change be reflected in the carrying value of assets and liabilities as of the first period presented and the offsetting adjustments are recorded to beginning retained earnings. Each period presented must be adjusted to reflect the period specific effects of applying the change. Also, under the new statement, a change in accounting estimate continues to be accounted for in the period of change and in future periods if necessary. Corrections of errors should continue to be reported by restating prior period financial statements as of the beginning of the first period presented, if material. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company will adopt SFAS 154 on October 1, 2006. Adoption will not have a material impact on the Company’s financial position and results of operations, since SFAS 154 is to be applied prospectively.


	Fiscal 2006		Fiscal 2007		Fiscal 2008
	(in millions, pre-tax)
Plans not currently expensed:
Stock Option Plan
Previously unvested grants	$	8.8	$	4.8	$	0.6
Estimated future grants		4.3		8.6		12.9
Stock Purchase Plan (estimate)		3.2		3.2		3.2

Additional Expense Under SFAS 123(R)		16.3		16.6		16.7

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)


	Fiscal 2006		Fiscal 2007		Fiscal 2008
	(in millions, pre-tax)
Plans currently expensed:
Stock Incentive Plan
Previously unvested grants		7.9		4.2		—
Estimated future grants		4.2		8.3		12.5

		12.1		12.5		12.5
Director Stock Awards
Previously unvested grants		0.5		0.1		—
Estimated future grants		0.5		0.9		1.0

		1.0		1.0		1.0


Total Estimated Expense	$	29.4	$	30.1	$	30.2

In December 2004, the FASB issued FASB Staff Position No. 109-2 (“FSP 109-2”), Accounting and Disclosure Guidance for the Foreign Repatriation Provision within the American Jobs Creation Act of 2004, which provides guidance under SFAS No. 109 with respect to recording the potential impact of the repatriation provisions of the Act on a company’s income tax expense and deferred tax liability. FSP 109-2 states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. The Company is considering the possibility of remitting dividends in excess of $20 million and perhaps materially in excess of $20 million in its next fiscal year to claim the benefits of this new provision. Furthermore, the Company believes that any residual U.S. tax liability from this possible repatriation would be fully offset with excess foreign tax credits of the Company.

3. Acquisitions of Businesses

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

On December 2, 2003, the Company acquired the assets and business of Petro-Drive, a division of Grant Prideco, Inc., for a total purchase price of $7 million. Petro-Drive, located in Lafayette, Louisiana, is a leading provider of hydraulic and diesel hammer services to the Gulf of Mexico market and select markets internationally. This business complements the Company’s casing and tubular services business in the Other Oilfield Services segment.

These acquisitions resulted in total goodwill of $6.2 million. Pro forma financial information is not presented, as the acquisitions were not material to the Company.

4. Earnings Per Share

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

The following table presents information necessary to calculate earnings per share for the three years ended September 30, 2005 (in thousands, except per share amounts):


	2005		2004		2003
Net Income	$	453,042	$	361,041	$	188,177
Weighted-average common shares outstanding		323,763		320,358		315,886

Basic earnings per share	$	1.40	$	1.13	$	.60

Weighted-average common and dilutive potential common shares outstanding:
Weighted-average common shares outstanding		323,763		320,358		315,886
Assumed exercise of stock options⁽¹⁾		5,352		6,470		6,628

Weighted-average dilutive shares outstanding		329,115		326,828		322,514

Diluted earnings per share	$	1.38	$	1.10	$	.58

⁽¹⁾

For the years ended September 30, 2005 and 2004, no stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect. For the year ended September 30, 2003, 134 thousand stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect.

5. Debt and Bank Credit Facilities

Long-term debt at September 30, 2005 and 2004 consisted of the following (in thousands):


	2005		2004
Convertible Senior Notes due 2022, net of discount	$	—	$	419,585
7% Series B Notes due February 1, 2006, net of discount		78,984		78,936

		78,984		498,521
Less current maturities of long-term debt		78,984		419,585

Long-term debt	$	—	$	78,936

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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, totaling $0.5 million in fiscal 2005. In addition, the Revolving Credit Facility charges a utilization 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 2005. There were no outstanding borrowings under the Revolving Credit Facility at September 30, 2005 or 2004.

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 were unsecured senior obligations that ranked 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. On April 25, 2005, the Company redeemed all of its outstanding convertible senior notes for a redemption price of $422.4 million. There was $419.6 million outstanding under the convertible senior notes at September 30, 2004.

At September 30, 2005 and September 30, 2004, the Company had issued and outstanding $79.0 million and $78.9 million, respectively, of unsecured 7% Series B Notes due February 1, 2006, net of discount.

In addition to the Revolving Credit Facility, the Company had $44.3 million of unsecured, discretionary lines of credit at September 30, 2005, which expire at the bank’s discretion. There are no requirements for commitment fees or compensating balances in connection with these lines of credit and interest is at prevailing market rates. There was $3.4 million and $3.8 million in outstanding borrowings under these lines of credit at September 30, 2005 and 2004, respectively. The weighted average interest rates on short-term borrowings outstanding as of September 30, 2005 and 2004 were 7.75% and 5.75%, respectively.

6. Financial Instruments

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

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

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

Foreign Exchange Contracts: Periodically, the Company borrows funds which are denominated in foreign currencies, which exposes the Company to market risk associated with exchange rate movements. There were no such borrowings denominated in foreign currencies at September 30, 2005 or 2004.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

The fair value of financial instruments that differed from their carrying value at September 30, 2005 and 2004 was as follows (in thousands):


	2005				2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7% Series B Notes	$	78,984	$	79,637	$	78,936	$	83,100
Convertible Senior Notes due 2022		—		—		419,585		447,004

7. Income Taxes

The geographical sources of income before income taxes for the three years ended September 30, 2005 were as follows (in thousands):


	2005		2004		2003
United States	$	425,399	$	342,983	$	123,337
Foreign		227,948		177,754		152,335

Income before income taxes	$	653,347	$	520,737	$	275,672

The provision for income taxes for the three years ended September 30, 2005 is summarized below (in thousands):


	2005			2004		2003
Current:
United States	$	130,088		$	29,387	$	3,154
Foreign		77,328			20,534		54,833

Total current		207,416			49,921		57,987
Deferred:
United States		9,587			81,368		36,141
Foreign		(16,698	)		28,407		(6,633	)

Total deferred		(7,111	)		109,775		29,508

Income tax expense	$	200,305		$	159,696	$	87,495

The consolidated effective income tax rates (as a percent of income (loss) before income taxes) for the three years ended September 30, 2005 varied from the United States statutory income tax rate for the reasons set forth below:


	2005		2004		2003
Statutory rate	35.0	%	35.0	%	35.0	%
Foreign earnings at varying rates	(3.6	)	(3.2	)	(3.5	)
State income taxes, net of federal benefit	0.6		0.3		0.3
Other taxes	1.1		0.0		0.0
Changes in valuation reserve	0.5		0.0		0.0
Foreign income recognized domestically	9.7		1.4		26.5
Amortization	(0.2	)	0.0		0.0
Tax credits	(12.3	)	(3.4	)	(26.9	)
Nondeductible expenses	0.5		0.1		0.3
Other, net	(0.6	)	0.5		0.0

	30.7	%	30.7	%	31.7	%

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of assets or liabilities and its reported amount in the financial statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rules currently in effect in each of the taxing jurisdictions in which the Company has operations. Generally, deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related asset or liability for financial reporting. The estimated deferred tax effect of temporary differences and carryforwards as of September 30, 2005 and 2004 were as follows (in thousands):


	2005			2004
Assets:
Accrued compensation expense	$	13,001		$	10,235
Accrued postretirement benefits		17,843			15,121
Deferred gain⁽¹⁾		9,386			10,781
Accrued insurance expense		6,701			5,039
Other accrued expenses		20,509			23,833
Foreign tax credit carryforwards		26,287			18,243
Other tax credit carryforwards		—			5,393
Net operating and capital loss carryforwards		18,578			15,790
Valuation allowance		(31,062	)		(23,986	)

Total deferred tax asset	$	81,243		$	80,449

Liabilities:
Differences in depreciable basis of property	$	(97,679	)	$	(85,854	)
Unrealized gain/loss		(7,604	)		(5,220	)
Income accrued for financial reporting purposes, not yet reported for tax		(523	)		(3,155	)

Total deferred tax liability		(105,806	)		(94,229	)

Net deferred tax liability	$	(24,563	)	$	(13,780	)

⁽¹⁾	Deferred gain on the contribution of pumping service equipment to the partnerships referred to in Note 10.

At September 30, 2005, the Company had approximately $53.8 million of foreign net operating loss carryforwards. The foreign net operating loss carryforwards expire as follows: $11.2 million by fiscal year 2010 and the remaining $42.6 million does not expire. The Company also had $26.3 million of US foreign tax credit carryforwards. Substantially all of these US foreign tax credits expire in 2012. The potential impact of the foreign net operating loss carryforwards and foreign tax credits subject to expiration has been reflected in the asset valuation allowance balance as of September 30, 2005. Furthermore, with respect to this valuation allowance, approximately $2.8 million of such valuation allowance, if subsequently realized, will be allocated to reduce goodwill.

The Company records a valuation allowance to reduce its deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will expire before realization of the benefit. The Company reached an IRS audit settlement with respect to its fiscal year 2002 tax return and received additional tax credits as a result of that audit resolution. Because it is more likely than not that these additional credits will not be realized, a valuation allowance has been recorded on these additional credits.

The Company’s stock basis difference in foreign subsidiaries, for which a U.S. deferred tax liability has not been established, is approximately $204 million as of September 30, 2005. This stock basis difference arises from the existence of unremitted foreign earnings and cumulative translation adjustments. The Company has provided additional taxes for the anticipated repatriation of foreign earnings of its foreign subsidiaries where it

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

has determined that the foreign subsidiaries earnings are not indefinitely reinvested. For foreign subsidiaries whose earnings are indefinitely reinvested, no provision for U.S. federal and state income taxes has been provided. If the Company were to record a tax liability for the full tax versus book basis difference of its foreign subsidiaries, an additional net deferred tax liability of approximately $15 million would be recorded.

8. Segment Information

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

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

The International Pressure Pumping segment has six operating segments. Similar to U.S./Mexico Pressure Pumping, it includes cementing and stimulation services (consisting of fracturing, acidizing, sand control, nitrogen, coiled tubing and service tool services). These services are provided to customers in more than 48 countries in the major international oil and natural gas producing areas of Canada, Latin America, Europe and Africa, Asia Pacific, Russia and the Middle East. The operating segments have been aggregated into one reportable segment because they have similar economic characteristics, offer the same type of services, have similar production processes and use the same methods to provide their services. They also serve the same or similar customers, which include major multi-national, independent and national or state-owned oil companies.

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

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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Summarized financial information concerning the Company’s segments for each of the three years ended September 30, 2005 is shown in the following tables (in thousands). The “Corporate” column includes corporate expenses not allocated to the operating segments. Revenue by geographic location is determined based on the location in which services are rendered or products are sold. For the years ended September 30, 2005, 2004 and 2003, the Company provided services to several thousand customers, none of which accounted for more than 5% of consolidated revenue.

Business Segments


	U.S./Mexico Pressure Pumping		International Pressure Pumping		Other Oilfield Services		Corporate			Total
2005
Revenue	$	1,683,202	$	1,041,910	$	517,650	$	424		$	3,243,186
Operating income (loss)		524,893		135,838		67,626		(91,298	)		637,059
Total assets		1,049,019		1,195,455		592,861		559,163			3,396,498
Capital expenditures		149,986		115,357		34,906		23,514			323,763
Depreciation		51,990		60,727		20,206		3,938			136,861

2004
Revenue	$	1,269,786	$	891,427	$	438,788	$	985		$	2,600,986
Operating income (loss)		337,030		91,409		54,030		(44,084	)		438,385
Total assets		901,272		1,056,728		549,051		783,646			3,290,697
Capital expenditures		92,080		62,688		31,704		14,105			200,577
Depreciation		45,699		56,414		19,492		4,063			125,668

2003
Revenue	$	982,630	$	801,746	$	358,479	$	22		$	2,142,877
Operating income (loss)		190,301		90,662		49,950		(37,672	)		293,241
Total assets		832,736		1,044,811		482,193		429,762			2,789,502
Capital expenditures		72,827		60,380		19,557		14,419			167,183
Depreciation		44,491		55,110		16,132		4,480			120,213

Geographic Information


	Revenue		Long-Lived Assets
2005
United States	$	1,820,191	$	1,519,193
Canada		392,380		172,609
Other countries		1,030,615		346,085

Consolidated total	$	3,243,186	$	2,037,887

2004
United States	$	1,357,139	$	1,385,343
Canada		331,521		114,642
Other countries		912,326		342,505

Consolidated total	$	2,600,986	$	1,842,490

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

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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Revenue by Product Line


	2005		2004		2003
Cementing	$	822,447	$	745,929	$	594,743
Stimulation		1,835,560		1,361,273		1,139,607
Other		585,179		493,784		408,527

Total revenue	$	3,243,186	$	2,600,986	$	2,142,877

A reconciliation from the segment information to consolidated income before income taxes for each of the three years ended September 30, 2005 is set forth below (in thousands):


	2005			2004			2003
Total operating profit for reportable segments	$	637,059		$	438,385		$	293,241
Interest expense		(10,951	)		(16,389	)		(15,948	)
Interest income		11,281			6,073			2,141
Other (expense) income, net		15,958			92,668			(3,762	)

Income before income taxes	$	653,347		$	520,737		$	275,672

9. Employee Benefit Plans

The Company administers defined contribution plans for employees in the U.S., the U.K and Canada whereby eligible employees may elect to contribute from 2% to 20% of their base salaries to an employee benefit trust. Employee contributions are matched by the Company at the rate of $.50 per $1.00 up to 6% of the employee’s base salary in the U.S., and an equal matching up to 5.5% of the employees base salary in the U.K. In addition, the Company contributes between 2% and 6% of each employee’s base salary depending on their age or years of service in the U.S., the U.K. and Canada. Company matching contributions vest immediately while Company base contributions become fully vested after five years of employment. The Company’s contributions to these defined contribution plans amounted to $16.6 million, $14.3 million, and $13.2 million, in 2005, 2004, and 2003, respectively.

Effective October 1, 2000, the Company established a non-qualified supplemental executive retirement plan. The unfunded defined benefit plan will provide Company executives with supplemental retirement benefits based on the highest consecutive three years compensation out of the final ten years and become vested at age 55. The expense associated with this plan was $2.1 million, $3.4 million, and $3.4 million for the years ended September 30, 2005, 2004, and 2003, respectively. The related accrued benefit obligation was $14.1 million and $13.0 million as of September 30, 2005 and 2004, respectively.

Effective December 7, 2000, the Company established a non-qualified directors’ benefit plan. The unfunded defined benefit plan will provide the Company’s non-employee directors with benefits upon termination of their service based on the number of years of service and the last annual retainer fee. The expense associated with this plan was $0.5 million, $0.1 million and $0.3 million for the years ended September 30, 2005, 2004, and 2003, respectively. The related accrued benefit obligation was $2.3 million and $1.8 million as of September 30, 2005 and 2004, respectively.

Defined Benefit Pension Plans

The Company has defined benefit pension plans covering employees in the U.S., the U.K., Norway and Canada. The defined benefit pension plan in the U.S. was frozen effective December 31, 1995, at which time all

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

earned benefits were vested. During fiscal 2004, the plans were frozen to new entrants in the U.K. and Canada. In addition, many employees in Canada converted from the defined benefit plan to the defined contribution plan (see “settlement benefits on conversion” in the defined benefit plan tables below). The Company uses a September 30 measurement date for these plans. All amounts are presented in thousands unless otherwise stated.

Obligations and Funded Status


	U.S.						Non-U.S.
	2005			2004			2005			2004
Change in benefit obligation
Benefit obligation, beginning of year	$	68,451		$	66,834		$	125,003		$	98,306
Service cost		—			—			4,823			4,452
Interest cost		3,826			3,802			7,609			6,254
Actuarial (gain)/loss		(4,163	)		1,115			14,635			9,310
Benefits paid from plan assets		(3,624	)		(3,300	)		(4,129	)		(2,029	)
Contributions by plan participants		—			—			2,155			1,825
Settlement of benefits on conversion		—			—			—			(1,719	)
Foreign currency exchange rate change		—			—			(338	)		8,604

Defined benefit plan obligation, end of year	$	64,490		$	68,451		$	149,758		$	125,003

Change in plan assets
Fair value of plan assets, beginning of year	$	64,765		$	48,197		$	85,026		$	67,654
Actual return on plan assets		6,883			6,002			16,248			7,771
Contributions by employer		1,058			13,866			7,757			5,523
Contributions by plan participants		—			—			2,155			1,825
Benefits paid from plan assets		(3,624	)		(3,300	)		(4,129	)		(2,029	)
Settlement of benefits on conversion		—			—			—			(1,787	)
Net refund from of plan		—			—			—			—
Foreign currency exchange rate change		—			—			160			6,069

Fair value of plan assets, end of year	$	69,082		$	64,765		$	107,217		$	85,026


Over (under) funded status	$	4,592		$	(3,686	)	$	(42,541	)	$	(39,977	)
Unrecognized net actuarial loss		15,526			21,816			43,061			40,622
Unrecognized prior service cost		—			—			23			50
Unrecognized transitional (gain) loss		—			—			(140	)		(100	)

Prepaid (accrued) net amount recognized	$	20,118		$	18,130		$	403		$	595

Amounts recognized in the consolidated statement of financial position consist of:


	U.S.					Non-U.S.
	2005		2004			2005			2004
Prepaid benefit cost	$	20,118	$	—		$	3,578		$	3,350
Accrued benefit cost		—		(3,686	)		(32,688	)		(32,982	)
Intangible assets		—		—			23			50
Accumulated other comprehensive income		—		21,816			29,490			30,177

Net amount recognized	$	20,118	$	18,130		$	403		$	595

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Accumulated Benefit Obligations (ABO) in Excess of Plan Assets

The ABO is the actuarial present value of the pension benefits at the employees’ current compensation levels. This differs from the projected benefit obligation, in that the ABO does not include any assumptions about future compensation levels. The ABO for all the plans was $197.2 million and $182.0 million at September 30, 2005 and 2004, respectively.


	U.S.				Non-U.S.
	2005		2004		2005		2004
Projected benefit obligation	$	64,490	$	68,451	$	149,758	$	125,003
Accumulated benefit obligation		64,490		68,451		132,719		113,580
Plan assets at fair value		69,082		64,765		107,217		85,026

Components of Net Periodic Benefit Cost


	U.S.									Non-U.S.
	2005			2004			2003			2005			2004			2003
Service cost for benefits earned	$	—		$	—		$	—		$	4,823		$	4,452		$	4,242
Interest on projected benefit obligation		3,826			3,802			3,902			7,609			6,254			4,836
Expected return on plan assets		(5,343	)		(4,010	)		(3,802	)		(6,898	)		(5,627	)		(4,281	)
Recognized actuarial loss		587			—			—			2,209			1,820			1,494
Net amortization		—			628			623			74			43			19

Net pension cost	$	(930	)	$	420		$	723		$	7,817		$	6,942		$	6,310

Additional Information


	U.S.						Non-U.S.
	2005			2004			2005		2004
Increase (decrease) in minimum liability included in other comprehensive income	$	(13,854	)	$	(1,506	)	$	57	$	3,869

Assumptions

Assumptions used to determine benefit obligations at September 30, were as follows:


	U.S.						Non-U.S.
	2005		2004		2003		2005		2004		2003
Weighted-average discount rate	5.7	%	5.8	%	5.9	%	5.0-5.5	%	5.8-6.3	%	5.6-6.6	%
Weighted-average expected long-term rate of return on assets	8.5	%	8.5	%	8.5	%	6.0-7.6	%	6.3-8.2	%	6.6-8.0	%

Assumptions used to determine net periodic benefit cost for the years ended September 30, were as follows:


	U.S.						Non-U.S.
	2005		2004		2003		2005		2004		2003
Weighted-average discount rate	5.8	%	5.8	%	5.9	%	5.0-5.5	%	5.8-6.3	%	5.6-6.6	%
Weighted-average expected long-term rate of return on assets	8.5	%	8.5	%	8.5	%	6.0-7.6	%	6.3-8.2	%	6.6-8.0	%
Weighted-average rate of increase in future compensation	N/A		N/A		N/A		3.5-4.5	%	3.8-4.5	%	3.0-4.5	%

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

The expected long-term rate of return assumptions represent the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. The assumption has been determined by reflecting expectations regarding future rates of return for the portfolio considering the asset distribution target and related historical rates of return. The redemption yield on government fixed interest bonds as well as corporate bonds were used as proxies for the return on debt securities, weighted by the relative proportion of each within the actual portfolio. The return on equities was based on the historical long-term performance of the equity classes. This rate is reassessed at least on an annual basis.

Plan Assets

The Company objective is to diversify the portfolio among several asset classes to reduce volatility while maintaining an asset mix that provides the highest rate of return with an acceptable risk. This is primarily through a mix of equity securities (between 60 - 75%) and fixed income funds (between 25 - 40%) to generate asset returns comparable with the general market.

The Company has investment committees that meet at least annually to review the portfolio returns and to determine asset-mix targets based on asset/liability studies. Nationally recognized third-party investment consultants assist the Company in developing an asset allocation strategy to determine the Company’s expected rate of return and expected risk for various investment portfolios. The investment committees considered these studies in the formal establishment of the current asset-mix targets based on the projected risk and return levels for each asset class.


	U.S.						Non-U.S.
	Target		2005		2004		Target		2005		2004
Equity securities	60	%	62	%	60	%	60-75	%	69	%	70	%
Debt securities	40	%	34	%	35	%	25-35	%	29	%	29	%
Other	0	%	4	%	5	%	0-5	%	2	%	1	%

Contributions and Estimated Benefit Payments

The pension plans are generally funded with the amounts necessary to meet the legal or contractual minimum funding requirements which totaled $8.8 million in fiscal 2005. The Company infrequently makes discretionary contributions, and a $9.0 million discretionary contribution was made to the U.S. plan in fiscal 2004. The Company expects to contribute $6.6 million to the defined benefit plans in fiscal 2006, which represents the legal or contractual minimum funding requirements.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


*Years ended September 30,*
2006	$	5,201
2007		5,381
2008		5,657
2009		6,140
2010		6,873
Years 2011-2015		38,486

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Postretirement Benefit Plans

The Company sponsors plans that provide certain health care and life insurance benefits for retired employees (primarily U.S.) who meet specified age and service requirements, and their eligible dependents. These plans are unfunded and the Company retains the right, subject to existing agreements, to modify or eliminate them. The Company’s postretirement medical benefit plan provides credits based on years of service that can be used to purchase coverage under the retiree plan. This plan effectively caps the Company’s health care inflation rate at a 4% increase per year. The Company uses a September 30 measurement date for these plans. All amounts are presented in thousands unless otherwise stated.

Obligations and Funded Status


	2005			2004
Change in benefit obligation
Benefit obligation, beginning of year	$	45,801		$	40,831
Service cost		3,295			2,915
Interest cost		2,634			2,389
Actuarial (gain)/loss		(1,333	)		243
Benefits paid from plan assets		(491	)		(577	)
Contributions by plan participants		—			—

Defined benefit plan obligation, end of year	$	49,906		$	45,801

Change in plan assets
Fair value of plan assets, beginning of year	$	—		$	—
Actual (loss) return on plan assets		—			—
Contributions by employer		491			577
Contributions by plan participants		—			—
Benefits paid from plan assets		(491	)		(577	)

Fair value of plan assets, end of year	$	—		$	—


Funded status	$	(49,906	)	$	(45,801	)
Unrecognized net actuarial loss		1,411			2,744
Unrecognized prior service cost		—			—

Prepaid (accrued) net amount recognized	$	(48,495	)	$	(43,057	)

The ABO was $49.9 million and $45.8 million at September 30, 2005 and 2004, respectively.

Amounts recognized in the consolidated statement of financial position consist of:


	2005			2004
Prepaid benefit cost	$	—		$	—
Accrued benefit cost		(48,495	)		(43,057	)
Intangible assets		—			—
Accumulated other comprehensive income		—			—

Net amount recognized	$	(48,495	)	$	(43,057	)

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

The postretirement benefit obligation at September 30, 2005 and 2004 was determined using a discount rate of 5.75% and 5.75%, respectively, and a health care cost trend rate of 4%, reflecting the cap described above. Increasing the assumed health care cost trend rates by one percentage point would not have a material impact on the accumulated postretirement benefit obligation or the net periodic postretirement benefit cost because these benefits are effectively capped by the Company.

Components of Net Periodic Benefit Cost


	2005		2004		2003
Service cost for benefits earned	$	3,295	$	2,915	$	2,531
Interest on projected benefit obligation		2,634		2,389		2,208
Expected return on plan assets		—		—		—
Recognized actuarial loss (gain)		—		—		50
Net amortization deferral		—		—		—

Net pension cost (benefit)	$	5,929	$	5,304	$	4,789

The postretirement benefit cost at September 30, 2005, 2004 and 2003 was determined using a discount rate of 5.75%, 5.85% and 6.50%, respectively, and a health care cost trend rate of 4%, reflecting the cap described above.

Contributions and Estimated Benefit Payments

The pension plans are generally funded with the amounts necessary to meet the legal or contractual minimum funding requirements. The Company expects to contribute $1.2 million to the postretirement plan in fiscal 2006, which represents the anticipated claims.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


*Years ended September 30,*
2006	$	1,171
2007		1,584
2008		2,004
2009		2,451
2010		2,956
Years 2011-2015		23,326

10. Commitments and Contingencies

Litigation

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Halliburton—Python Litigation

Newfield Litigation

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

U.S. Court of Appeals for the Fifth Circuit, both with regard to the liability case and the insurance coverage issues. Oral argument was held on April 4, 2005, and the parties are awaiting a ruling. Great Lakes Chemical Corporation, which formerly 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 $5.6 million. The Company is fully reserved for its share of this liability.

Asbestos Litigation

U.S. Commerce Department Settlement Agreement

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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 $2.5 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.

Lease and Other Long-Term Commitments

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 “Equipment financing arrangements” in the Contractual Cash Obligations table below. 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 (“FIN 46”). 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 $22.1 million and $26.6 million as of September 30, 2005 and September 30, 2004, 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 April 2005 and 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 $1.1 million and $3.3 million, respectively. In October 2005, the Company received another partnership approval to substitute certain pumping services equipment, further reducing the deferred gain by $1.4 million. In September 2010, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. Currently, the Company expects to purchase the pumping service equipment in 2010.

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 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 “Equipment financing arrangements” in the Contractual Cash Obligations table below. The Company assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46. 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 $0.3 million and $0.4 million as of September 30, 2005 and September 30, 2004, 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

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

July 2004. In June 2009, the Company has the option, but not the obligation, to purchase the pumping service equipment for approximately $27 million. Currently, the Company expects to purchase the pumping service equipment in 2009.

At September 30, 2003, the Company had long-term operating leases and service fee commitments covering certain facilities and equipment, as well as other long-term commitments, with varying expiration dates. Minimum annual commitments for the years ending September 30, 2006, 2007, 2008, 2009 and 2010 are $63.8 million, $46.9 million, $37.3 million, $26.7 million and $10.2 million, respectively and $12.2 million in the aggregate thereafter.

Contractual Obligations


			Amount of commitment expiration per period
Other Commercial Commitments	Total Amounts Committed		Less than 1 Year		1–3 Years		4–5 Years		Over 5 Years
Standby Letters of Credit	$	28,994	$	28,990	$	4	$	—	$	—
Guarantees		204,302		154,307		37,506		9,992		2,497

Total Other Commercial Commitments	$	233,296	$	183,297	$	37,510	$	9,992	$	2,497

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

The following table summarizes the Company’s contractual cash obligations and other commercial commitments as of September 30, 2005 (in thousands):


Contractual Cash Obligations	Total		Less than 1 year		1-3 Years		4-5 Years		After 5 Years
Long term and short term debt ⁽¹⁾	$	78,984	$	78,984	$	—	$	—	$	—
Interest on long term debt and capital leases		2,832		2,797		35		—		—
Capital lease obligations		455		130		325		—		—
Operating leases		107,641		38,755		37,238		18,897		12,751
Equipment financing arrangements⁽²⁾		146,675		23,919		47,615		43,141		32,000
Purchase obligations⁽³⁾		144,827		144,447		380		—		—
Other long-term liabilities⁽⁴⁾		76,440		6,726		228		96		69,390

Total contractual cash obligations	$	557,854	$	295,758	$	85,821	$	62,134	$	114,141

⁽¹⁾	Net of original issue discounts.

⁽²⁾

As discussed previously, the Company has the option, but not the obligation, to purchase the pumping service equipment in these two partnerships for approximately $27 million and $32 million in 2009 and 2010, respectively. Currently, the Company expects to purchase the pumping service equipment and has therefore included it in the table above.

⁽³⁾	Includes agreements to purchase goods or services that have been approved and that specify all significant terms (pricing, quantity and timing). Company policy does not require a purchase order to be completed for items that are under $200 and are for miscellaneous items, such as office supplies.

⁽⁴⁾

Includes expected cash payments for long-term liabilities reflected in the consolidated balance sheet where the amounts and timing of the payment are known. Amounts include: Asset retirement obligations, known pension funding requirements, post-retirement benefit obligation, environmental accruals and other miscellaneous long-term obligations. Amounts exclude: Deferred gains (see “Lease and Other Long-Term Commitments” above), pension obligations in which funding requirements are uncertain and long-term contingent liabilities.

11. Investment in Affiliates

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

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

Societe Algerienne de Stimulation de Puits Producteurs d’Hydroncarbures (“BJSP”) – the purpose of BJSP is to perform services such as casing, cementing, stimulation and well testing in Algeria. BJ Service International, Inc. (a wholly owned subsidiary of the Company) owns 49% of BJSP and L’Enterprise de Services aux Puits owns the remaining 51%. The current agreement expires in March 2006. The contract can be extended by mutual agreement of the stockholders and the Company is currently negotiating to extend the agreement. Profits and losses are shared by the stockholders in proportion to their ownership percentages.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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

At September 30, 2005 and 2004, combined net accounts receivable reflected in our Consolidated Statement of Financial Position from unconsolidated affiliates totaled $6.5 million and $20.6 million, respectively. At September 30, 2005 and 2004, combined accounts payable reflected in our Consolidated Statement of Financial Position to unconsolidated affiliates totaled $0.2 million and $0.1 million, respectively. The Company’s combined investment on September 30, 2005 and 2004 was $11.6 million and $10.2 million, respectively. The Company recognized revenue of $30.2 million, $51.3 million, and $35.9 million for the years ended September 30, 2005, 2004, and 2003, respectively, primarily for services performed on behalf of its equity affiliates.

12. Supplemental Financial Information

Supplemental financial information for the three years ended September 30, 2005 is as follows (in thousands):


	2005			2004		2003
Consolidated Statement of Operations:
Research and development expense	$	21,172		$	20,414	$	19,103
Rent expense		75,811			73,072		74,788
Net operating foreign exchange loss (gain)		(740	)		608		(1,057	)
Consolidated Statement of Cash Flows:
Income taxes paid	$	187,195		$	52,355	$	57,460
Interest paid		8,078			8,073		8,193
Details of acquisitions:
Fair value of assets acquired		—			9,254		—
Liabilities assumed		—			112		—
Goodwill		—			6,195		—
Cash paid for acquisitions, net of cash acquired		—			15,337		—

Other (expense) income, net for the three years ended September 30, 2005 is summarized as follows (in thousands):


	2005			2004			2003
Rental income	$	159		$	214		$	219
Minority interest		(3,725	)		(2,286	)		(5,080	)
Non-operating net foreign exchange gain / (loss)		746			(146	)		448
Gain on insurance recovery		239			272			1,694
Gain (loss) from equity method investments		1,546			(6,605	)		(3,393	)
Refund of indirect taxes		85			705			1,344
Halliburton award (see Note 10)		—			86,413			—
Recovery of misappropriated funds (see below)		9,020			—			—
Reversal of excess liabilities in the Asia Pacific region (see below)		9,484			12,206			—
Other, net		(1,596	)		1,895			1,006

Other (expense) income, net	$	15,958		$	92,668		$	(3,762	)

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)


	2005			2004
Gross reduction of other accrued liabilities	$	2.8		$	10.6
Adjustments of and reclassifications to balance sheet accounts		7.6			(7.8	)

Net reduction of excess accruals		10.4			2.8
(Addition) reduction of minority interest liability		(0.9	)		9.4

Net increase to income before tax		9.5			12.2
Income tax provision		(2.9	)		(.9	)

Total increase to net income	$	6.6		$	11.3

The net effect of these adjustments was reported in Other Income in the Consolidated Statement of Operations for the years ended September 30, 2005 and 2004.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

cases, the Company has not yet been able to establish the legitimacy of the transactions reflected in the underlying documents and in other cases there are questions about the adequacy of the underlying documents to support the accounting entries. Such payments may prove to have been proper, but due to circumstances surrounding the payments, the Company continues to investigate to determine whether theft or other improprieties may have been involved. Such payments have been previously expensed, and therefore the Company believes that no additional expense is required to be recorded for such payments.

As discussed in our Annual Report on Form 10-K for the period ended September 30, 2004, the misappropriations and related accounting adjustments in the Asia Pacific Region were possible because of certain internal control operating deficiencies. During fiscal 2002, the Company implemented policy changes worldwide for disbursements. In March 2005, the Company assigned a new Controller, an Assistant Controller and several new accountants to the Asia Pacific region. In addition, we have put in place Control and Process Improvement Managers at each of our six regional bases world-wide to document, enhance and test our control processes. The Company has also made several enhancements to its accounting policies and procedures. In 2005 the Company adopted new policies and procedures for the retention of international commercial agents. The Company is still in the process of reviewing its control policies and procedures and may make further enhancements.

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


	Minimum Pension Liability Adjustment			Cumulative Translation Adjustment		Total
Balance, September 30, 2002	$	(29,960	)	$	87	$	(29,873	)

Changes		(1,230	)		21,456		20,226

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

Changes		(1,729	)		10,468		8,739

Balance, September 30, 2004	$	(32,919	)	$	32,011	$	(908	)

Changes		13,797			11,482		25,279

Balance, September 30, 2005	$	(19,122	)	$	43,493	$	24,371

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

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


	Before-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Year Ended September 30, 2003:
Foreign currency translation adjustment	$	21,456		$	—		$	21,456
Minimum pension liability adjustment		(1,767	)		537			(1,230	)

Change in other comprehensive income	$	19,689		$	537		$	20,226

Year Ended September 30, 2004:
Foreign currency translation adjustment	$	10,468		$	—		$	10,468
Minimum pension liability adjustment		(2,363	)		634			(1,729	)

Change in other comprehensive income	$	8,105		$	634		$	8,739

Year Ended September 30, 2005:
Foreign currency translation adjustment	$	11,482		$	—		$	11,482
Minimum pension liability adjustment		21,783			(7,986	)		13,797

Change in other comprehensive income	$	33,265		$	(7,986	)	$	25,279

13. Employee Stock Plans

Stock Option Plans: The Company’s 1995 Incentive Plan, 1997 Incentive Plan, 2000 Incentive Plan and 2003 Incentive Plan (the “Plans”) provide for the granting of stock options to officers, key employees and nonemployee directors at an exercise price equal to the fair market value of the stock at the date of the grant. Options vest over three or four-year periods and are exercisable for periods ranging from one to ten years. An aggregate of 32,000,000 shares of Common Stock has been authorized for grants, of which 12,827,616 were available for future grants at September 30, 2005.

A summary of the status of the Company’s stock option activity and related information for each of the three years ended September 30, 2005 is presented below (in thousands, except per share prices):


	2005				2004				2003
	Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
Outstanding at beginning of year	9,675		$	12.26	13,280		$	10.11	14,175		$	9.55
Granted	1,929			23.15	2,217			15.91	690			16.46
Exercised	(2,814	)		11.81	(5,692	)		8.63	(1,404	)		7.29
Forfeited	(175	)		20.32	(130	)		13.65	(181	)		12.15

Outstanding at end of year	8,615			14.68	9,675			12.26	13,280			10.11

Options exercisable at year-end	5,279			11.41	4,967			10.83	7,525			8.53
Weighted-average grant date fair value of options granted during the year			$	6.99			$	6.07			$	7.04

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

The following table summarizes information about stock options outstanding as of September 30, 2005 (in thousands, except per share prices and remaining life):


	Options Outstanding				Options Exercisable
Range of Exercise Price	Shares	Weighted-Average Remaining Contractual Life	Weighted- Average Exercise Price		Shares	Weighted- Average Exercise Price
$ 2.35 – 4.70	386	3.0	$	3.53	386	$	3.53
4.70 – 7.05	81	3.7		6.90	81		6.90
7.05 – 9.40	291	2.2		8.95	291		8.95
9.40 – 11.76	3,130	3.0		10.82	3,130		10.82
11.76 – 14.11	34	3.1		13.82	34		13.82
14.11 – 16.46	2,540	4.3		15.72	1,175		15.50
16.46 – 18.81	340	4.0		16.95	182		17.37
18.81 – 23.51	1,813	6.1		23.15	—

	8,615	4.1		14.68	5,279		11.41

Stock Purchase Plan: The Company’s 1999 Employee Stock Purchase Plan (the “Purchase Plan”) allows all employees to purchase shares of the Company’s Common Stock at 85% of market value on the first or last business day of the twelve-month plan period beginning each October, whichever is lower. Purchases are limited to 10% of an employee’s regular salary. A maximum aggregate of 12,000,000 shares has been reserved under the Purchase Plan, 7,008,626 of which were available for future purchase at September 30, 2005. A total of 572,322 shares were purchased at $22.27 per share during fiscal 2005, 837,174 shares were purchased at $14.52 per share during fiscal 2004 and 990,028 shares were purchased at $11.05 per share during fiscal 2003. The Company has reserved a total of 565,433 shares for fiscal 2006.

Stock Incentive Plan: Pursuant to the terms of the 1997 Stock Incentive Plan and 2000 Stock Incentive Plan, the Company reserved 860,106 Performance Units (“Units”), representing the maximum number of Units the officers could receive. Each Unit represents the right to receive from the Company at the end of a stipulated period one unrestricted share of Common Stock, contingent upon achievement of certain financial performance goals over the stipulated period. Should the Company fail to achieve the specific financial goals as set by the Executive Compensation Committee of the Board of Directors, the Units are canceled and the related shares revert to the Company for reissuance under the plan. The aggregate fair market value of the underlying shares granted under this plan is considered unearned compensation at the time of grant and is adjusted quarterly based on the current market price for the Common Stock. Compensation expense is determined based on management’s current estimate of the likelihood of meeting the specific financial goals and expensed ratably over the stipulated period. The Executive Compensation Committee of the Board of Directors reviewed the Company’s three year performance and determined that the highest level of performance criteria was achieved for the Unit awards and in November 2003, a total of 190,252 Units were converted into stock and issued to officers. In November 2006, 405,166 Units will be assessed for the three-year performance period of the Company ending September 30, 2006. The remaining balance in the reserve will be assessed for the three-year performance period of the Company ending September 30, 2007. In November 2005, the Company awarded an additional 194,673 Units.

Director Stock Awards: In addition to stock option awards, the nonemployee directors may be granted an award of common stock of the Company with no exercise price (“restricted stock”). Stock option and restricted stock awards vest over three or four-year periods, if they are still a director for the Company at the end of the period, and are exercisable for periods ranging from one to ten years. Upon retirement, vesting may accelerate. Restricted stock awards total of 79,896 as of September 30, 2005, of which 10,632 were exercisable.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

Compensation expense is valued using a Black-Scholes model and is expensed using graded vesting. In November 2005, the Company granted an additional restricted stock award of 48,000 to nonemployee directors.

14. Stockholders’ Equity

Common Stock: The Board of Directors has unanimously approved the charter amendment increasing the authorized number of shares of common stock from 380,000,000 shares to 980,000,000 shares, which requires stockholder approval.

Dividends: The Company’s Board of Directors approved a 2 for 1 stock split to be effected in the form of a stock dividend payable on September 1, 2005 to stockholders of record as of August 18, 2005. Share and earnings per share amounts have been restated for all periods presented to reflect the increased number of common shares outstanding. 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. The Company paid cash dividends in the amount of $.04 per common share on a quarterly basis and $51.9 million in the aggregate annual amount during fiscal 2005. On July 28, 2005 the Company’s Board of Directors approved a 25% increase in the quarterly cash dividend and declared a cash dividend of $.05 per common share payable on October 15, 2005 to shareholders of record on September 15, 2005, in the aggregate amount of $16.1 million. The Company anticipates paying cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2006. However, dividends are subject to approval of the Company’s Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

Stockholder Rights Plan: The Company has a Stockholder Rights Plan (the “Rights Plan”) designed to deter coercive takeover tactics and to prevent an acquirer from gaining control of the Company without offering a fair price to all of 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-eighth 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, 2001, and 2005, one Right is associated with eight outstanding shares of common stock. The purchase price for the one-eighth of a Right associated with one share of common stock is effectively $65. 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.

Treasury Stock: In December 1997, the Board of Directors approved a share repurchase program authorizing purchases of up to $150 million of Common Stock at the discretion of the Company’s management. The Board subsequently increased the authorized amount to $300 million in May 1998, to $450 million in September 2000, to $600 million in July 2001 and again to $750 million in October 2001. Under this program, the Company has repurchased a total of 48,366,000 shares at a cost of $499.0 million through fiscal 2002. In fiscal 2005, there were 3,982,000 shares purchased at a cost of $98.4 million. No shares were repurchased in fiscal 2004 or 2003. Treasury shares have been utilized for the Company’s various stock plans as described in Note 13. A total of 3,655 treasury shares were used at a cost of $45.2 million in fiscal 2005, 7,126 treasury shares were used at a cost of $60.1 million in fiscal 2004, and 3,022 treasury shares were used at a cost of $20.1 million in fiscal 2003.

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

15. Quarterly Financial Data (Unaudited)


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Fiscal Year Total
	(in thousands, except per share amounts)
Fiscal Year 2005:
Revenue	$	737,782	$	795,863	$	817,261	$	892,280	$	3,243,186
Gross profit⁽¹⁾		175,234		209,187		216,065		254,305		854,791
Net income⁽²⁾		95,033		109,554		114,193		134,262		453,042
Earnings per share:
Basic		.29		.34		.35		.42		1.40
Diluted		.29		.33		.35		.41		1.38

Fiscal Year 2004:
Revenue	$	600,799	$	647,060	$	658,662	$	694,465	$	2,600,986
Gross profit⁽¹⁾		132,564		151,126		148,255		170,732		602,677
Net income⁽²⁾		61,513		73,264		129,287		96,978		361,041
Earnings per share:
Basic		.19		.23		.40		.30		1.13
Diluted		.19		.22		.39		.29		1.10

⁽¹⁾	Represents revenue less cost of sales and services and research and engineering expenses.

⁽²⁾	Includes Halliburton patent infringement award of $86.4 million (net of legal expenses) in fiscal 2004 (see Note 10 of the Notes to the Consolidated Financial Statements).

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. Based on their evaluation of the Company’s disclosure controls and procedures as of the end of the period covered by this report, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the Company’s disclosure controls and procedures are effective.

Changes in internal control over financial reporting. There has been no change in the Company’s internal controls over financial reporting during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.

Design and evaluation of internal control over financial reporting. Management’s Report on Internal Control over Financial Reporting and the Report of the Independent Registered Public Accounting Firm are set forth in Part II, Item 8 of this report and are incorporated herein by reference.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information concerning the directors of the Company is set forth in the section entitled “Proposal 1: Election of Directors” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which section is incorporated herein by reference. For information regarding executive officers of the Company, see page 16 hereof. Information concerning compliance with Section 16(a) of the Exchange Act is set forth in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which section is incorporated herein by reference.

Information concerning the Audit Committee of the Company and the audit committee financial expert is set forth in the section entitled “Board of Directors and Committees of the Board” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which section is incorporated herein by reference. Information concerning the Company’s Code of Ethics is set forth in the section entitled “Code of Ethics” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which section is incorporated herein by reference.

ITEM 11.

EXECUTIVE COMPENSATION

Information for this item is set forth in the sections entitled “Board of Directors and Committees of the Board,” “Executive Compensation” and “Severance Agreements” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which sections are incorporated herein by reference.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information for this item is set forth in the sections entitled “Voting Securities”, “Beneficial Ownership of Directors and Executive Officers” and “Equity Compensation Plan Information” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which sections are incorporated herein by reference.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information for this item is set forth in the section entitled “Certain Relationships and Related Transactions” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be January 31, 2006, which section is incorporated herein by reference.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information for this item is set forth in the section entitled “Independent Auditor” in the Proxy Statement of the Company for the Annual Meeting of Stockholders to be held January 31, 2006, which section is incorporated herein by reference.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) List of documents filed as part of this report or incorporated herein by reference:

(1) Financial Statements:

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


		Page in this Form 10-K
Report of Independent Registered Public Accounting Firm		44
Consolidated Statement of Operations for the years ended September 30, 2005, 2004 and 2003		46
Consolidated Statement of Financial Position as of September 30, 2005 and 2004		47
Consolidated Statement of Stockholders’ Equity for the years ended September 30, 2005, 2004 and 2003		49
Consolidated Statement of Cash Flows for the years ended September 30, 2005, 2004 and 2003		50
Notes to Consolidated Financial Statements		51

(2) Financial Statement Schedules:


Schedule Number	Description of Schedule	Page Number
II	Valuation and Qualifying Accounts	92

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

(3) Exhibits:


Exhibit Number		Description of Exhibit
2.1		Agreement and Plan of Merger dated as of November 17, 1994 (“Merger Agreement”), among BJ Services Company, WCNA Acquisition Corp. and The Western Company of North America (filed as Exhibit 2.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1995 (file no. 1-10570), and incorporated herein by reference).

2.2		First Amendment to Agreement and Plan of Merger dated March 7, 1995, among BJ Services Company, WCNA Acquisition Corp. and The Western Company of North America (filed as Exhibit 2.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1995 (file no. 1-10570), and incorporated herein by reference).

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

3.1		Certificate of Incorporation, as amended as of October 22, 1996 (filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570) and incorporated herein by reference).

3.2		Certificate of Amendment to Certificate of Incorporation, dated January 22, 1998 (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570) and incorporated herein by reference).


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

3.4		Certificate of Designation of Series A Junior Participating Preferred Stock, as amended, dated September 26, 1996 (filed as Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1996 (file no. 1-10570) and incorporated herein by reference).

3.6		Amended and Restated Bylaws, as of May 26, 2005 (filed as Exhibit 3.(ii).1 to the Company’s Report on Form 8-K filed on June 2, 2005 and incorporated herein by reference).

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

4.2		Amended and Restated Rights Agreement, dated September 26, 1996, between the Company and First Chicago Trust Company of New York, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-K dated October 21, 1996 (file no. 1-10570) and incorporated herein by reference).

4.3		First Amendment to Amended and Restated Rights Agreement and Appointment of Rights Agent, dated March 31, 1997, among the Company, First Chicago Trust Company of New York and The Bank of New York, as successor Rights Agent (filed as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 (file no. 1-10570) and incorporated herein by reference).

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

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

4.6		First Supplemental Indenture, dated as of July 24, 2001, among the Company, BJ Services Company, U.S.A., BJ Services Company Middle East, BJ Service International, Inc. and The Bank of New York, as successor Trustee (filed as Exhibit 4.5 to the Company’s Form 8-A/A, filed on November 14, 2001, with respect to the Company’s preferred share purchase rights and incorporated herein by reference).

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

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

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


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

†10.4		Amendment effective December 12, 1996, to 1990 Stock Incentive Plan, as amended and restated (filed as Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1996 (file no. 1-10570), and incorporated herein by reference).

†10.5		Amendment effective July 22, 1999 to 1990 Stock Incentive Plan (filed as Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570), and incorporated herein by reference).

†10.6		Amendment effective January 27, 2000 to 1990 Stock Incentive Plan (filed as Appendix A to the Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

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

†10.8		Amendments effective January 25, 1996, and December 12, 1996, to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1996 (file no. 1-10570), and incorporated herein by reference).

†10.9		Amendment effective July 22, 1999 to BJ Services Company 1995 Incentive Plan (filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570), and incorporated herein by reference).

†10.10		Amendment effective January 27, 2000 to BJ Services Company 1995 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

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

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

†10.13		1997 Incentive Plan (filed as Appendix B to the Company’s Proxy Statement dated December 22, 1997 (file no. 1-10570) and incorporated herein by reference).

†10.14		Amendment effective July 22, 1999 to 1997 Incentive Plan (filed as Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1999 (file no. 1-10570), and incorporated herein by reference).

†10.15		Amendment effective January 27, 2000 to 1997 Incentive Plan (filed as Appendix C to the Company’s Proxy Statement dated December 20, 1999 (file no. 1-10570) and incorporated herein by reference).

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

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

†10.18		1999 Employee Stock Purchase Plan (filed as Appendix A to the Company’s Proxy Statement dated December 21, 1998 (file no. 1-10570) and incorporated herein by reference).


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

†10.20		Third Amendment effective September 1, 2001 to BJ Services Company 1999 Employee Stock Purchase Plan. (filed as Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference)

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

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

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

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

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

†10.26		Key Employee Security Option Plan (filed as Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 (file no. 1-10570) and incorporated herein by reference).

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

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

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

10.30		Trust Indenture and Security Agreement dated as of August 7, 1997 among First Security Bank, National Association, BJ Services Equipment, L.P. and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.15 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 (file no. 1-10570) and incorporated herein by reference).

10.31		Indenture Supplement No. 1 dated as of August 8, 1997 between First Security Bank, as Nonaffiliated Partner Trustee, and BJ Services Equipment, L.P., and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.17 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 (file no. 1-10570) and incorporated herein by reference).

10.32		Amended and Restated Agreement of Limited Partnership dated as of August 7, 1997 of BJ Services Equipment, L.P (filed as Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended September 30, 1997 (file no. 1-10570) and incorporated herein by reference).


Exhibit Number		Description of Exhibit
10.33		Trust Indenture and Security Agreement dated as of December 15, 1999 among First Security Trust Company of Nevada, BJ Services Equipment II, L.P. and State Street Bank and Trust Company, as Indenture Trustee (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 15, 1999 (file no. 1-10570) and incorporated herein by reference).

10.34		Amended and Restated Agreement of Agreement of Limited Partnership dated as of December 15, 1999 of BJ Services Equipment II, L.P. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K dated December 15, 1999 (file no. 1-10570) and incorporated herein by reference).

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

†10.36		Second Amendment, effective March 22, 2001, to BJ Services Company 1999 Employee Stock Purchase Plan (filed as Exhibit 10.40 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†10.37		Fourth Amendment, effective December 4, 2003, to BJ Services Company 1999 Employee Stock Purchase Plan (filed as Exhibit 10.41 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†10.38		First Amendment, effective September 25, 2003, to BJ Services Company Supplemental Executive Retirement Plan (filed as Exhibit 10.42 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†10.39		BJ Services Company 2003 Incentive Plan (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2003 and incorporated herein by reference).

†10.40		Credit Agreement, dated as of June 11, 2004 among the Company, the lenders from time to time party thereto, The Bank of New York and Citibank, N.A., as Co-Syndication Agents, The Royal Bank of Scotland plc and Bank One, N.A., as Co-Documentation Agents, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer (filed as Exhibit 10.44 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.41		Form of Indemnification Agreement, dated as of December 9, 2004 between the Company and its directors and executive officers. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on December 15, 2004, and incorporated herein by reference).

†10.42		Form of letter agreement setting forth terms and conditions of shares of phantom stock awarded to non-employee directors of the Company on November 17, 2004 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on November 23, 2004, and incorporated herein by reference).

†10.43		Form of letter agreement setting forth terms and conditions of performance units awarded to executive officers of the Company for performance in fiscal 2004 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed on November 23, 2004, and incorporated herein by reference).

†10.44		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to non-employee directors on November 17, 2004 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed on November 23, 2004, and incorporated herein by reference).

†10.45		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers for performance in fiscal 2004 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K, filed on November 23, 2004, and incorporated herein by reference).


Exhibit Number		Description of Exhibit

†10.46		First Amendment to BJ Services Deferred Compensation Plan effective January 1, 2002 (filed as Exhibit 10.50 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.47		Fifth Amendment to 1999 Employee Stock Purchase Plan, effective October 1, 2004 (filed as Exhibit 10.51 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.48		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to non-employee directors during fiscal 2000 (filed as Exhibit 10.52 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.49		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to non-employee directors during fiscal 2001 and 2003 (filed as Exhibit 10.53 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.50		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to non-employee directors during fiscal 2004 (filed as Exhibit 10.54 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.51		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 1997 (filed as Exhibit 10.55 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.52		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 1998 (filed as Exhibit 10.56 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.53		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 1999 (filed as Exhibit 10.57 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.54		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2001 (filed as Exhibit 10.58 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.55		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2002 (filed as Exhibit 10.59 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.56		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2003 (filed as Exhibit 10.60 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).


Exhibit Number		Description of Exhibit

†10.57		Form of letter agreement setting forth terms and conditions of options to purchase shares of common stock awarded to executive officers during fiscal 2004 (filed as Exhibit 10.61 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.58		Form of letter agreement setting forth terms and conditions of performance units awarded to executive officers during fiscal 2004 (filed as Exhibit 10.62 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

†10.59		Form of letter agreement setting forth terms and conditions of phantom stock awarded to non-employee directors during fiscal 2004 (filed as Exhibit 10.63 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2004 and incorporated herein by reference).

*12.1		Ratio of Earnings to Fixed Charges.

14.1		Code of Ethics (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

*21.1		Subsidiaries of the Company.

*23.1		Consent of Deloitte & Touche LLP.

*31.1		Section 302 certification for J. W. Stewart.

*31.2		Section 302 certification for T. M. Whichard.

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

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

†99.1		Charter of the Nominating and Governance Committee of the Board of Directors (filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†99.2		Charter of the Compensation Committee of the Board of Directors (filed as Exhibit 10.44 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†99.3		Charter of the Audit Committee of the Board of Directors (filed as Exhibit 10.45 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

†99.4		Board of Directors Corporate Governance Guidelines (filed as Exhibit 10.46 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2003 and incorporated herein by reference).

*	Filed herewith.

†	Management contract or compensatory plan or arrangement.

SIGNATURES

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


BJ SERVICES COMPANY

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

Date: December 14, 2005

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


Signature	Title	Date

/S/ J.W. STEWART J.W. Stewart	Chairman of the Board, President, and Chief Executive Officer (Principal Executive Officer)	December 14, 2005

/S/ T. M. WHICHARD T. M. Whichard	Vice President—Finance, and Chief Financial Officer (Principal Financial Officer)	December 14, 2005

/S/ BRIAN T. MCCOLE Brian T. McCole	Controller (Principal Accounting Officer)	December 14, 2005

/S/ L. WILLIAM HEILIGBRODT L. William Heiligbrodt	Director	December 14, 2005

/S/ JOHN R. HUFF John R. Huff	Director	December 14, 2005

/S/ DON D. JORDAN Don D. Jordan	Director	December 14, 2005

/S/ WILLIAM H. WHITE William H. White	Director	December 14, 2005

/S/ MICHAEL E. PATRICK Michael E. Patrick	Director	December 14, 2005

/S/ JAMES L. PAYNE James L. Payne	Director	December 14, 2005

BJ SERVICES COMPANY

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended September 30, 2003, 2004 and 2005

(in thousands)


			Additions
	Balance at Beginning Of Period		Charged to Expense		Charged to Other Accounts			Deductions			Balance at End of Period
YEAR ENDED SEPTEMBER 30, 2003
Allowance for doubtful accounts receivable	$	14,097	$	139	$	63		$	(5,471	)⁽¹⁾	$	8,828
Reserve for inventory obsolescence		9,780		2,078		1,208			(1,256	)⁽²⁾		11,810

YEAR ENDED SEPTEMBER 30, 2004
Allowance for doubtful accounts receivable	$	8,828	$	2,646	$	55		$	(2,519	)⁽¹⁾	$	9,010
Reserve for inventory obsolescence		11,810		2,937		4,902	⁽³⁾		(3,505	)⁽²⁾		16,144

YEAR ENDED SEPTEMBER 30, 2005
Allowance for doubtful accounts receivable	$	9,010	$	6,811	$	258		$	(2,141	)⁽¹⁾	$	13,938
Reserve for inventory obsolescence		16,144		5,667		(88	)		(4,294	)⁽²⁾		17,429

⁽¹⁾	Deductions in the allowance for doubtful accounts principally reflect the write-off of previously reserved accounts.

⁽²⁾	Deductions in the reserve for inventory obsolescence and adjustment principally reflect the sale or disposal of related inventory.

⁽³⁾	Reserve was previously netted against the inventory balance and an adjustment was made to reflect the gross amount of the reserve during fiscal 2004.