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BJ SERVICES CO LLC 10-K 2007
Form 10-K for the Fiscal Year Ended September 30, 2007
Table of Contents

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, 2007

OR

 

¨ 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 incorporation or organization)   (I.R.S. Employer Identification No.)

4601 Westway Park Blvd, Houston, Texas 77041

(Address of principal executive offices)

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

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

 


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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  ¨.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or non accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

Large accelerated filer  þ            Accelerated filer  ¨            Non-accelerated filer  ¨

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

At November 26, 2007, the registrant had outstanding 292,825,124 shares of Common Stock, $.10 par value per share. The aggregate market value of the Common Stock on March 31, 2007 (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 $8.2 billion.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s Proxy Statement for the Annual Meeting of Stockholders to be held February 7, 2008 are incorporated by reference into Part III of this Form 10-K.

 



Table of Contents

TABLE OF CONTENTS

 

PART I

     

Item 1.

  

Business

   3

Item 1A.

  

Risk Factors

   14

Item 1B.

  

Unresolved Staff Comments

   17

Item 2.

  

Properties

   17

Item 3.

  

Legal Proceedings

   18

Item 4.

  

Submission of Matters to a Vote of Security Holders

   18

PART II

     

Item 5.

  

Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   19

Item 6.

  

Selected Financial Data

   21

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   22

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   39

Item 8.

  

Financial Statements and Supplementary Data

   40

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   79

Item 9A.

  

Controls and Procedures

   79

Item 9B.

  

Other Information

   79

PART III

     

Item 10.

  

Directors, Executive Officers and Corporate Governance

   80

Item 11.

  

Executive Compensation

   80

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   80

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

   80

Item 14.

  

Principal Accountant Fees and Services

   80

PART IV

     

Item 15.

  

Exhibits and Financial Statement Schedules

   81

 

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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. We are a leading worldwide provider of pressure pumping and oilfield services for the petroleum industry. 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. Oilfield services include completion tools, completion fluids, casing and tubular services, chemical services, and precommissioning, maintenance and turnaround services in the pipeline and process business, including pipeline inspection.

During the year ended September 30, 2007, we generated approximately 84% of our revenue from pressure pumping services and 16% from the oilfield services group. Over the same period, we generated approximately 60% of our revenue from United States operations and 40% from international operations. For segment and geographic information for each of the three years ended September 30, 2007, see Note 8 of the Notes to the Consolidated Financial Statements.

We conduct our operations through four principal segments:

 

   

U.S./Mexico Pressure Pumping Services. This segment includes pressure pumping services derived from our activities in the United States and Mexico.

 

   

International Pressure Pumping Services. This segment includes pressure pumping services derived from our activities outside of the U.S., Mexico and Canada.

 

   

Canada Pressure Pumping Services. This segment includes pressure pumping services derived from our activities in Canada.

 

   

Oilfield Services Group. This segment includes the following oilfield service divisions: casing and tubular services, process and pipeline services, chemical services, completion tools, and completion fluids.

Pressure Pumping Services

Our pressure pumping services consist of cementing services and stimulation services. Stimulation services includes fracturing, acidizing, sand control, nitrogen services, coiled tubing, and service tools. We provide pressure pumping services to major and independent oil and natural gas producing companies, as well as national oil companies. 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 producing 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

Our cementing services, which accounted for approximately 31% of total pressure pumping revenue during fiscal 2007, consist of blending high-grade cement and water with various solid and liquid additives to create a “cement slurry” that is pumped into a well between the casing and the wellbore. The 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.

We provide central, regional and district laboratory testing services to evaluate cement slurry properties, which can vary by cement supplier and local water sources. Our field engineers develop job design recommendations to achieve desired compressive strength and bonding characteristics.

 

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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

Our stimulation services, which accounted for approximately 69% of total pressure pumping revenue during fiscal 2007, consist of fracturing, acidizing, sand control, nitrogen services, coiled tubing and service tools. Stimulation services are provided both onshore and offshore. Offshore services are provided through the use of skid-mounted pumping units and the operation of several stimulation vessels.

We believe that as oil and natural gas production continues to decline in key producing fields in the U.S. and certain international regions and as the development of unconventional hydrocarbon reservoirs increases, the demand for fracturing and other stimulation services is likely to increase. Fracturing is a critical element involved in the successful completion of unconventional reservoirs including “tight” or low permeability sandstones, coal-bed methane and gas bearing shale. Consequently, we have been increasing our pressure pumping capabilities in the U.S. and internationally over the past several years. Stimulation 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. Our fracturing units are capable of pumping slurries at pressures of up to 20,000 pounds per square inch.

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. Our 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. We have introduced equipment and products to respond to these technological advances.

In 1998, we embarked on a program to replace our aging U.S. fracturing pump fleet with new, more efficient and higher horsepower pressure pumping equipment. We have since expanded the U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment and have made significant progress in adding new equipment. However, much of the older equipment still remains in operation due to increased market activity. We plan to continue adding new equipment to our fleet. The market activity level at the time the equipment is ready for use will determine if the new equipment will be used for expansion or used as replacement assets. At the end of fiscal 2007, approximately 20% of our U.S. fleet remained as candidates for future replacement as part of our recapitalization initiative.

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

 

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the flow of hydrocarbons 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. We maintain a fleet of mobile acid transport and pumping units to provide acidizing services for the onshore market and maintain acid storage and pumping equipment on most of our 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. Our completion tools, as described later, 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 our coiled tubing and stimulation services.

Coiled Tubing. Coiled tubing services involve injecting coiled tubing into wells to perform various well-servicing operations. Coiled tubing is a flexible steel pipe with a diameter of less than five inches manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck-mounted reel for onshore applications or skid-mounted for offshore applications. Due to the small diameter of coiled tubing, it can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas 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. We have 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. We provide 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 production in a well, generally are rented from us. While marketed separately, service tools are usually provided during the course of providing other pressure pumping services.

Oilfield Services Group

Our oilfield services group accounted for approximately 16% of our total revenue in fiscal 2007. This segment consists of casing and tubular services, process and pipeline services, chemical services, 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 isolate 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 of a well. Our casing and tubular services business also provides pipe driving hammer services. Hydraulic and diesel powered hammers are used in a variety of offshore well construction projects.

 

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Process and Pipeline Services

We provide 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: (1) the precommissioning of new plants and (2) 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 chemically treating to ensure debris is removed from the system prior to start-up, thus minimizing damage to expensive process equipment.

Due to regulatory requirements or safety concerns, new pipelines are often tested prior to their initial use. During fiscal 2007, we added subsea umbilical and pipeline testing capability through the acquisition of Norson Services Limited. 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. We offer several techniques for pipeline cleaning, which include gel cleaning, which is used to carry large amounts of debris out of the pipeline, and various solvent treatments to remove debris.

Our pipeline inspection business uses “intelligent pigs” to assist pipeline operators in assessing the integrity of their pipelines. Pigs are electromagnetic devices that are propelled through a pipeline, recording information about the pipeline. We have developed two principal sets of pipeline inspection tools: one set of tools monitors metal loss from the interior pipe wall caused by either corrosion or mechanical damage utilizing electromagnetic based instruments. A second set of tools monitor 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.

Chemical Services

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 optimize production, unload wellbore fluids and 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 and injection services operations address four principal priorities our customers have: (1) the protection of the customer’s capital investment in metal goods, such as downhole casing and tubing, pipelines and process vessels, (2) deliquification of wellbore fluids providing steady state flow and enhanced production, (3) 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, and (4) through the acquisitions of Dyna-Coil in August 2006 and the capillary string business of Allis-Chalmers in June 2007, the injection of production chemicals directly to the desired producing zone through the use of small diameter capillary strings.

Completion Tools

We design, build and install downhole completion tools that utilize gravel and sand control screens to control the migration of reservoir sand into the well and direct the flow of oil and natural gas into the production tubing. We have a specialty tool manufacturing plant in Houston, Texas that manufactures many of the components required in the completion tools; however some components are manufactured by third parties. In addition, spare parts for completion tools and production packers are sold to customers that have purchased tools in the past.

 

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Our 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, we have the ability to install tools that can either isolate one producing zone from another or integrate the production from multiple producing zones. Our field specialists, working with the rig crews, deploy completion tools in the well during the completion process.

To further enhance reservoir optimization, we have also developed tools to provide the operator with “intelligent completion” capabilities. These tools allow the operator to selectively control flow from multiple productive zones in the same wellbore from a remote surface site. From time to time, we 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, we also provide completion tools that are generally used in conventional completions for reservoirs that do not require sand control. These tools include production packers, surface controlled subsurface safety valves, and other tools that are delivered through distribution networks located in key domestic markets and select international markets.

We have 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. These 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

We sell and reclaim clear completion fluids and perform 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. We provide basic 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, should not restrict the flow of oil and natural gas from the formation. 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 remain in the well after drilling mud is displaced. To remove these contaminants, we deploy filtering equipment and technicians that work in conjunction with our on-site fluid engineers to maintain the solids-free condition of the completion fluids throughout the project. We provide 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. In addition, we provide a wide range of downhole tools with chemical systems for removing drilling fluid debris from a well during completion operations.

With the acquisition of Tekcor Technology, Ltd. in December 2006 we entered into the business of providing a unique system for delivery of lost circulation materials used in conjunction with completion operations.

Raw Materials and Equipment

Principal materials used in pressure pumping include cement, fracturing proppants, acid, polymers, nitrogen, and other specialty chemical additives. We purchase our principal materials from several suppliers and produce

 

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certain materials at our own blending facilities in Germany, Singapore, Canada, the U.S. and Brazil. Sufficient material inventories are generally maintained to allow us to provide on-call services to our pressure pumping customers. We have continued to experience intermittent tightness in supply for certain types of cement and fracturing proppants but have been able to use alternatives with customer acceptance, and it is not expected to materially hinder operations. In addition, we have entered into agreements to ensure certain levels of materials are maintained in the U.S. and Canada.

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 us 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. We believe our pressure pumping equipment is adequate to service both current and projected levels of market activity in the near term. As the market increases demand for our services, we will continue to add needed capacity in select markets.

Repair parts and maintenance items for pressure pumping equipment are held in inventory at levels that we believe will allow continued operations without significant downtime. We have experienced only intermittent tightness in supply or extended lead times in obtaining necessary supplies of these materials or repair parts. We do not depend on any single source of supply for any of these parts and materials; however, loss of one or more of our suppliers could disrupt operations.

We believe that coiled tubing and other materials used in performing coiled tubing services are and will continue to be widely available. Although there are only two principal manufacturers of the coiled tubing, we have not experienced any difficulty in obtaining coiled tubing in the past and do not anticipate difficulty in the foreseeable future.

Nitrogen is one of the principal materials used in our process and pipeline services division. We purchase nitrogen from several suppliers. We have experienced only intermittent tightness in supply or extended lead times in obtaining nitrogen and do not expect any chronic shortage of nitrogen in the foreseeable future.

Engineering Support

Our engineering support department is divided into the following areas: Software Applications, Instrumentation Engineering, Mechanical Engineering, Coiled Tubing Engineering and Completion Tools Engineering.

Software Applications

Our 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 our internally developed monitoring hardware, allows for real-time job control and post-job analysis.

Instrumentation Engineering

We use an array of monitoring and control instrumentation, which is an integral element of providing cementing and stimulation services. Our monitoring and control instrumentation, developed by our instrumentation engineering group, complements our products and equipment and provides customers with real-time monitoring of critical applications.

Mechanical Engineering

Our mechanical engineering group is responsible for the design of virtually all of our primary pumping and blending equipment. Though similarities exist among the major pressure pumping competitors in the general

 

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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.

Coiled Tubing Engineering

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

Completion Tools Engineering

The completion tools engineering group specializes in the design, manufacture 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

We own two primary manufacturing facilities in the Houston, Texas area. Our technology center in Tomball, Texas houses our main equipment manufacturing facility, primarily serving pressure pumping services. Our other facility in the Houston, Texas area produces certain components and spare parts required for the assembly of downhole completion tools, service tools and well screens. We also have strategic manufacturing facilities located in Calgary and Singapore to support our global manufacturing efforts. We employ outside vendors for manufacturing various units and for engine and transmission rebuilding and certain fabrication work, but we are not dependent on any one vendor.

Competition

Pressure Pumping Services

There are two primary companies with which we compete 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 we operate. Halliburton Energy Services and Schlumberger are larger in terms of overall pressure pumping revenue. We also compete with Weatherford International, Inc. and numerous smaller companies including Calfrac Well Services Ltd., Trican Well Service Ltd., San Antonio and Frac Tech Services, Ltd. During 2007, we have experienced increased competition in the U.S. market from these and other new competitors. Competitive factors impacting our business are prices, technology, service record and reputation in the industry.

Oilfield Services Group

We believe that we are one of the largest suppliers of casing and tubular services in the North Sea and have expanded these services into other international markets in the past several years. The largest worldwide provider of casing and tubular services is Weatherford International, Inc. In addition, we compete with Frank’s International Inc. in the Gulf of Mexico and certain international markets.

We believe we are 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.

 

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There are several competitors significantly larger than us in chemical services.

Our 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 Ltd; and Tetra Technologies, Inc.

Our principal competitors in completion tools are Halliburton Energy Services, a division of Halliburton Company, Schlumberger Ltd, Baker Hughes Inc. and Weatherford International, Inc. Competitive factors impacting our business are prices, technology, service record and reputation in the industry.

Markets and Customers

Demand for our 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 the Canadian spring break-up, we are 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.

Our principal customers consist of major and independent oil and natural gas producing companies, as well as national oil companies. During fiscal 2007, we provided services to several thousand customers, none of which accounted for more than 5% of consolidated revenue. While the loss of certain of our largest customers could have a material adverse effect on our revenue and operating results in the near term, we believe we would be able to obtain other customers for our services in the event of a loss of any of our largest customers.

United States

The United States is the largest single pressure pumping market in the world. We provide pressure pumping services to our 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 our 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 1,749 in fiscal 2007, a 10% increase over the fiscal 2006 average U.S. rig count of 1,587. In fiscal 2006, the average U.S. rig count was 20% higher than the fiscal 2005 U.S. rig count average of 1,323.

International

We operate in approximately 50 countries which encompass the major international oil and natural gas producing areas of Latin America, Europe, Africa, Russia, Asia and the Middle East. We generally provide services to international customers through wholly-owned foreign subsidiaries. Additionally, we hold controlling or minority interests in several joint venture companies through which we conduct a portion of our 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 50 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 616 in fiscal 1999 and the highest international rig count averaged 989 in fiscal 2007, a 9% increase over the fiscal 2006 average international rig count of 905. In fiscal 2006, the average international rig count was 9% higher than the fiscal 2005 international rig count average of 833.

 

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In fiscal 2005, we opened an office in Libya and started operations there during fiscal 2006. Since 1986, we have been involved in the pumping services business in Algeria through minority interest participation in a company known as Societe Algerienne de Stimulation de Puits Producteurs d’Hydrocabures (BJSP). In June 2006, we participated in a recapitalization of BJSP which resulted in the Company becoming the majority interest partner and operator of the joint venture. Also in fiscal 2006, operating bases in New Zealand, Uzbekistan and Oman were opened. In fiscal 2007, we began operation of stimulation vessels in India and began fracturing work in Australia.

We operate in most of the major oil and natural gas producing regions of the world. International operations are subject to risks that can materially affect our sales and profits, including currency exchange rate fluctuations, inflation, governmental expropriation, currency 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 we invoice for work performed in certain countries in both U.S. dollars and local currency. We attempt to match the amounts invoiced in local currency with the amount of expenses denominated in local currency.

Canada

The Canadian market is very similar to the U.S. in that demand for our pressure pumping services 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 Canadian rig count averaged 212 in fiscal 1999 and the highest Canadian rig count averaged 502 in fiscal 2006, a 20% increase over the fiscal 2005 average rig count of 420. In fiscal 2007, the average rig count was 365, 27% lower than the fiscal 2006 rig count average. The results of operations in Canada are impacted by seasonality during Canadian spring break-up. During the annual spring break-up, typically our third fiscal quarter, this region experiences a significant decline in revenue and operating income.

Our Canadian operations are subject to currency exchange rate fluctuations. The Canadian dollar is the functional currency for this segment. The risk of currency exchange rate fluctuations and its impact on net income are mitigated by using natural hedges in which we invoice for work performed in both U.S. dollars and Canadian dollars. We attempt to match the amounts invoiced in Canadian dollars with the amount of expenses denominated in Canadian dollars. As such, currency exchange rate fluctuations may have a significant impact on our revenues, but we attempt to minimize the impact on operating income by utilizing natural hedges.

Employees

At September 30, 2007, we employed approximately 16,700 personnel around the world. Approximately 59% of our employees were employed outside the United States. As we experience expanding activity levels in certain markets, we have encountered intermittent labor shortages. As in the past, we have 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

Our business is affected both directly and indirectly by governmental regulations on a worldwide basis relating to the oil and natural gas industry in general, as well as environmental and safety regulations which have specific application to our business.

Through the routine course of providing services, we handle and store bulk quantities of hazardous materials. If leaks or spills of hazardous materials handled, transported, or stored by us occur, we may be responsible under applicable environmental laws for costs of remediating any damage to the surface or sub-surface (including aquifers). Accordingly, we have implemented and continue to implement various procedures for the handling and disposal of hazardous materials. Such procedures are designed to minimize the

 

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occurrence of spills or leaks of these materials. In addition, leak detection services, provided through our process and pipeline division, involve the inspection and testing of facilities for leaks of hazardous or volatile substances.

We have implemented and continue to implement various procedures to further assure our 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 our facilities. In addition, we maintain insurance for certain environmental liabilities, which we believe is reasonable based on our 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 us or our predecessors have been investigated under state and federal Superfund statutes, and we are currently named as a potentially responsible party for cleanup at four such sites. Although our level of involvement varies at each site, we are 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, we believe that the ultimate resolutions should not have a materially adverse effect on our results of operations or financial position.

Research and Development

Our research and development activities are focused on improving existing products and services and developing new technologies designed to meet industry and customer needs. We currently hold numerous patents both inside and outside of the U.S. having remaining duration. Although such patents, in the aggregate, are important to maintaining our competitive position, no single patent is considered to be of a critical or essential nature to our ongoing operations. We also use 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 our overall operations.

We intend to continue to devote significant resources to research and development efforts. For information regarding the amounts of research and development expenses for each of the three fiscal years ended September 30, 2007, see Note 12 of the Notes to the Consolidated Financial Statements.

Some of our key patented and patent pending technologies include:

 

 

(1)

fracturing fluids, such as our high-performance SPECTRA FRAC G® and low-polymer loading VISTAR®;

 

 

(2)

our LITE PROP® low-density proppants capable of producing 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;

 

 

(3)

water control systems for reducing undesirable water production while increasing oil or natural gas production using our relative water permeability modifier, AQUACON;

 

 

(4)

well cleanout systems, including the TORNADO® and SANDVAC® systems, effective at removing sand and other fill material from wells at much greater efficiencies than previously obtainable;

 

 

(5)

surface-controlled sub-surface safety valves, including our FLOWSAFE WR wireline-retrievable and FLOWSAFE TR tubing-retrievable valves;

 

  (6) completion tool systems for conventional completions and horizontal well completions in both gravel-packed and conventional configuration, and interventionless intelligent completion systems; and

 

 

(7)

our INJECTSAFE wireline surface-controlled sub-surface safety valve system provides the functionality of a wireline-retrievable safety valve with an integral capillary tubing flow path to allow continuous chemical treatment up to 22,000 feet (6,700 meters) below the safety valve without interruption or risk to the safety valve.

 

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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 our internet website at http://www.bjservices.com. In addition, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our 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 100 F Street, N.E., 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

Our current executive officers and their positions and ages are as follows:

 

Name

   Age   

Position

   Office
Held
Since

J. W. Stewart

   63    Chairman of the Board, President and Chief Executive Officer    1990

Alasdair Buchanan

   47    Vice President—International Pressure Pumping Services    2007

Ronald F. Coleman

   52    Vice President—North America Pressure Pumping Services    2007

Susan Douget

   47    Vice President—Human Resources    2003

David Dunlap

   46    Executive Vice President—Chief Operating Officer    2007

Jeff Hibbeler

   42    Vice President—Technology and Logistics    2007

Brian T. McCole

   48    Vice President—Controller    2002

Margaret B. Shannon

   58    Vice President—General Counsel    1994

Jeffrey E. Smith

   45    Senior Vice President—Finance and Chief Financial Officer    2006

Bret Wells

   42    Vice President—Treasurer and Chief Tax Officer    2006

Paul Yust

   54    Vice President—Chief Information Officer    2006

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. Buchanan joined the Company in 1982 as a Trainee Engineer and was named Vice President—International Pressure Pumping Services in 2007. He served as Vice President—Technology and Logistics from 2005 through 2007 and has previously served in numerous international Engineering and Operations positions, including Region Manager of the Europe Africa Region, a position he had held from 1999 through 2005.

Mr. Coleman joined the Company in 1977 and was named Vice President—North American Pressure Pumping Services in 2007. Prior to be promoted to Vice President—North America Pressure Pumping Services, he held the position of Vice President U.S./Mexico Operations from 1998 through 2007. He previously held various management positions within U.S./Mexico sales and operations.

Ms. Douget joined the Company in 1979 and was promoted to Director, Human Resources in 2003 and then to Vice President in 2007. Prior to being promoted to Director, she held various positions within the Human Resources function.

Mr. Dunlap joined the Company in 1984 as a District Engineer and was named Executive Vice President—Chief Operating Officer in 2007. Prior to being promoted to Executive Vice President and Chief Operating

 

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Officer, he held the position of Vice President—International Division from 1995 through 2007. He also previously served as Vice President—Sales for the Coastal Division of North America and U.S. Sales and Marketing Manager.

Mr. Hibbeler joined the Company in 1989 as an Associate Engineer and was named Vice President—Technology and Logistics in 2007. He has previously served as Region Manager for Asia Pacific. Prior to that, he held the position of Country Manager for several countries in Asia Pacific and Latin America.

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 and was promoted to Vice President in 2007.

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 and the Director of Business Development. He held the position of Treasurer from 2002 through 2006 and was named Vice President, Finance and Chief Financial Officer in 2006. In 2007, Mr. Smith was promoted to Senior Vice President.

Mr. Wells joined the Company as Tax Director in 2002. Prior to that date, Mr. Wells worked the majority of his career at Cargill, Inc. where he served as Assistant Vice President—Tax. He was named Treasurer and Chief Tax Officer in 2006 and was promoted to Vice President in 2007.

Mr. Yust joined the Company as Chief Information Officer in 2006 and was promoted to Vice President in 2007. He joined the Company from Kraton Polymers LLC, a multinational chemical manufacturing and distribution company, where he served as the Chief Information Officer from 2001 until 2005.

ITEM 1A. Risk Factors

This document, and our 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 our prospects, expected revenue, expenses and profits, strategies for our 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 our 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

Our results of operations could be adversely affected if our business assumptions do not prove to be accurate or if adverse changes occur in our business environment, including the following areas:

 

   

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,

 

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general global economic and business conditions,

 

   

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

 

   

our ability to expand our products and services (including those we acquire) into new geographic markets,

 

   

our ability to grow businesses we have acquired such that our investment can be fully realized

 

   

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 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 us,

 

   

competition and consolidation in our business, including the addition of new competitors and new capacity in the U.S.,

 

   

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

 

   

other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission.

Risks of Economic Downturn and Lower Oil and Natural Gas Prices

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 lower demand for our products and services. Our 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. A decline in oil and natural gas prices for any reason could reduce demand for our services.

Risks from Operating Hazards

Our operations are subject to hazards present in the oil and natural gas industry, such as fire, explosion, blowouts, oil spills and leaks or spills of hazardous materials. 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 us for damage to their equipment or property that occurred while we were 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 our products in oil and natural gas wells and refineries, and

 

   

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

 

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Risks from Litigation

We have insurance coverage against some operating hazards. This insurance has deductibles or self-insured retentions and contains certain coverage exclusions. Our insurance premiums can be increased or decreased based on the claims made by us under our insurance policies. The insurance does not cover damages from breach of contract by us or based on alleged fraud or deceptive trade practices. Whenever possible, we obtain agreements from customers that limit our liability. Insurance and customer agreements do not provide complete protection against losses and risks, and our results of operations could be adversely affected by 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 business or consolidated financial statements.

Risks from International Operations

Our international operations are subject to special risks that can materially affect our 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 reduce drilling operations,

 

   

fluctuations and changes in currency exchange rates,

 

   

the impact of inflation,

 

   

the ultimate tax liability may be significantly different due to different interpretations of local tax laws and tax treaties, estimates and assumptions made regarding the scope of and timing of income earned and changes in tax laws,

 

   

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

 

   

terrorist attacks and threats of attacks have increased the political and economic instability in some of the countries in which we operate, and

 

   

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

 

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Weather

Our 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 our 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 Rating

If our 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.

The market price for our common stock, as well as other companies in the oil and natural gas industry, has been historically volatile.

Many of these risks are beyond our control. 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.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

We own our corporate office in Houston, Texas. 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, we own two primary manufacturing facilities in the Houston, Texas area. Our research and technology center in Tomball, Texas houses our main equipment and instrumentation manufacturing operation, primarily serving pressure pumping services. Our facility in Houston, Texas produces certain components and spare parts required for the assembly of downhole completion tools, service tools and well screens. We also have strategic manufacturing facilities to support our global manufacturing efforts located in Calgary and Singapore.

 

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Our equipment consists primarily of pressure pumping and blending units and related support equipment such as bulk storage and transport units. Although a portion of our 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 our worldwide fleet is owned and unencumbered. Our tractor fleet, most of which is owned, is used to transport the pumping and blending units. The majority of our light duty truck fleet, both in the U.S. and international operations, is also owned.

We believe our facilities and equipment are adequate for our current operations, although growth of our business in certain areas may require facility expansion or new facilities. For additional information with respect to our lease commitments, see Note 10 of the Notes to the Consolidated Financial Statements.

ITEM 3. Legal Proceedings

The information regarding litigation and environmental matters described in Note 10 of the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K is incorporated herein by reference.

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, 2007.

 

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PART II

 

ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock began trading on The New York Stock Exchange (“NYSE”) in July 1990 under the symbol “BJS”. At November 26, 2007, there were approximately 1,342 holders of record of our common stock.

The table below sets forth for the periods indicated the high and low sales prices per share for our common stock reported on the NYSE composite tape.

 

     Common Stock
Price Range
     High    Low

Fiscal 2007

     

1st Quarter

   $ 34.14    $ 27.43

2nd Quarter

     29.10      25.55

3rd Quarter

     31.26      27.25

4th Quarter

     29.52      23.48

Fiscal 2006

     

1st Quarter

   $ 39.78    $ 30.89

2nd Quarter

     42.85      30.25

3rd Quarter

     41.79      31.81

4th Quarter

     38.01      27.87

At September 30, 2007, there were 347,510,648 shares of common stock issued and 291,735,636 shares outstanding. On January 31, 2006, our stockholders approved a charter amendment increasing the authorized number of shares of common stock from 380,000,000 shares to 910,000,000 shares.

Stock Repurchases

On December 19, 1997, our Board of Directors authorized a stock repurchase program of up to $150 million. Through a series of increases, the stock repurchase program was increased to $2.2 billion. Repurchases are made at the discretion of management and the program will remain in effect until terminated by our Board of Directors. We purchased 52,348,000 shares at a cost of $597.4 million through fiscal 2005. During fiscal 2006, we purchased a total of 31,725,882 shares at a cost of $1,133.3 million. During fiscal 2007, we purchased a total of 2,564,457 shares at a cost of $74.6 million. We currently have remaining authorization to purchase up to an additional $394.7 million in stock.

We made no purchases of equity securities during the quarter ended September 30, 2007.

Dividend Program

We have paid cash dividends in the amount of $.05 per common share each quarter for fiscal years 2006 and 2007. We anticipate paying cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2008. However, dividends are subject to approval by our Board of Directors each quarter, and the Board has the ability to change the dividend policy at any time.

 

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Performance Graph—Total Stockholder Return

The following is a line graph comparing cumulative, five-year total shareholder return with a general market index (the S&P 500) and a group of peers in the same line of business or industry selected by the Company. The peer group is comprised of the following companies: Baker Hughes Incorporated, Halliburton Company, Schlumberger N.V., Smith International, Inc., and Weatherford International Ltd.

The graph assumes investments of $100 on September 30, 2002 and the reinvestment of all dividends.

The graph shall not be deemed incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates this information by reference, and shall not otherwise be deemed filed under such Acts.

LOGO

 

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ITEM 6. Selected Financial Data

The following table sets forth certain selected historical financial data and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto which are included elsewhere herein. The selected operating and financial position data as of and for each of the five years for the period ended September 30, 2007 have been derived from our audited consolidated financial statements, some of which appear elsewhere in this Annual Report on Form 10-K. Our historical results are not necessarily indicative of results to be expected in future periods.

 

     As of and For the Year Ended September 30,  
     2007     2006     2005     2004     2003  
     (in thousands, except per share amounts)  

Operating Data

          

Revenue

   $ 4,802,409     $ 4,367,864     $ 3,243,186     $ 2,600,986     $ 2,142,877  

Operating expenses

     (3,651,870 )     (3,196,128 )     (2,606,127 )     (2,162,601 )     (1,849,636 )
                                        

Operating income

     1,150,539       1,171,736       637,059       438,385       293,241  

Interest expense

     (32,731 )     (14,558 )     (10,951 )     (16,389 )     (15,948 )

Interest income

     1,624       14,916       11,281       6,073       2,141  

Other income (expense), net(1)

     (6,584 )     (11 )     15,958       92,668       (3,762 )

Income tax expense

     (359,208 )     (367,473 )     (200,305 )     (159,696 )     (87,495 )
                                        

Net income

     753,640       804,610       453,042       361,041       188,177  
                                        

Earnings per share(2):

          

Basic

     2.57       2.55       1.40       1.13       .60  

Diluted

     2.55       2.52       1.38       1.10       .58  

Depreciation and amortization

     209,019       166,763       136,861       125,668       120,213  

Capital expenditures(3)

     752,113       459,974       323,763       200,577       167,183  

Financial Position Data (at end of period):

          

Property, net

   $ 1,965,719     $ 1,392,926     $ 1,086,932     $ 913,713     $ 850,340  

Total assets

     4,715,212       3,862,288       3,409,642       3,301,330       2,800,135  

Long-term debt and capital leases, excluding current maturities

     252,709       500,140       455       78,936       493,754  

Stockholders’ equity

     2,851,398       2,146,940       2,492,041       2,102,424       1,658,920  

Cash dividends declared per common share

     .20       .20       .17       .04    

(1)

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

(2)

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 effective September 1, 2005.

(3)

Excluding acquisitions of businesses. Includes $47.8 million in fiscal 2007 to purchase assets from an equipment financing partnership. See Note 10 of the Notes to the Consolidated Financial Statements.

 

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Business

We are engaged in providing pressure pumping services and other oilfield services to the oil and natural gas industry worldwide. Services are provided through four business segments: U.S./Mexico Pressure Pumping, International Pressure Pumping, Canada Pressure Pumping and the Oilfield Services Group.

The U.S./Mexico, International Pressure Pumping and Canada 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 Oilfield Services Group consists of 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.

Market Conditions

Our 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 our revenue and profitability, especially in the United States and Canada, where we have historically generated in excess of 50% of our revenue. Historical market conditions are reflected in the table below for the twelve months ended September 30:

 

     2007    % Change     2006    % Change     2005

Worldwide Rig Count(1):

            

U.S.  

     1,749    10 %     1,587    20 %     1,323

International(2)

     989    9 %     905    9 %     833

Canada

     365    -27 %     502    20 %     420

Commodity Prices (average):

            

Crude Oil (West Texas Intermediate)

   $ 64.62    -2 %   $ 66.06    23 %   $ 53.52

Natural Gas (Henry Hub)

   $ 6.90    -15 %   $ 8.16    10 %   $ 7.40

(1)

Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.

(2)

Includes Mexico rig count of 90, 85 and 111 for the fiscal years ended September 30, 2007, 2006 and 2005, respectively.

U.S. Rig Count

Demand for our 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 crude oil and natural gas. During the last 10 years, the lowest annual U.S. rig count averaged 601 in fiscal 1999 and the highest annual U.S. rig count averaged 1,749 in fiscal 2007.

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, our international revenue in total is less volatile because we operate in approximately 50 countries, which provides a reduction of exposure to any one country. Due to the

significant investment and complexity of international projects, we believe drilling decisions relating to such

 

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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 annual international rig count, excluding Canada and including Mexico, averaged 616 in fiscal 1999 and the highest annual international rig count averaged 989 in fiscal 2007.

Canadian Rig Count

The demand for our pressure pumping services in Canada is primarily driven by oil and natural gas drilling activity, and similar to the U.S., tends to be extremely volatile. During the last 10 years, the lowest annual rig count averaged 212 in fiscal 1999 and the highest annual rig count averaged 502 in fiscal 2006.

Acquisitions

Fiscal 2007

On November 3, 2006, we completed the acquisition of Profile International Ltd. (“Profile”) for a total purchase price of $2.5 million, which resulted in $2.2 million of goodwill. Profile, located in Newcastle, England, provides caliper inspection tools for pipeline integrity assessment to markets worldwide. This business complements our pipeline inspection business in the Oilfield Services Group segment.

On December 20, 2006, we purchased substantially all of the operating assets of Tekcor Technology, Ltd. (“Tekcor”) for $8.3 million, which resulted in an increase of $3.6 million to total current assets, $0.7 million in property and equipment and $4.0 million to technology based intangible assets. Tekcor provides specialty chemicals and related services to the oil and gas well drilling industry. Located in Houston, Texas, Tekcor services markets along the Texas and Louisiana Gulf Coast and is included in our completion fluids business in the Oilfield Services Group segment.

On March 1, 2007 we acquired Aberdeen-based Norson Services Ltd, (“Norson”), a division of Norson Group Ltd., and substantially all of the assets of Norson Group’s United States subsidiary Norson Services LLC. The total purchase price paid for both acquisitions was $29.0 million, including legal fees, which resulted in an increase of $7.4 million in total current assets, $5.9 million in property and equipment, $1.8 million in intangible assets, $5.4 million in current liabilities and $19.3 million of goodwill. The acquisition strengthens our service capabilities with the addition of Norson’s hydraulic and electrical umbilical testing services and the services provided by the Norson’s subsea units, which include remote pigging and flooding, subsea hydro testing and subsea data logging. This business complements our process and pipeline business in the Oilfield Services Group segment.

On June 30, 2007, we completed the acquisition of substantially all of the capillary tubing assets of Allis-Chalmers for a total purchase price of $16.3 million, which resulted in an increase of $1.5 million in current assets, $1.8 in property and equipment and $13.0 million of goodwill. The assets are used for the installation and service of capillary injection systems primarily in the U.S. and Mexico. The assets complement our Dyna-Coil acquisition which occurred in the fourth quarter of fiscal 2006 and will enhance our chemical services operation in the Oilfield Services Group segment.

Fiscal 2006

On June 25, 2006, we acquired an additional 2% interest in our Algerian joint venture, Societe Algerienne de Stimulation de Puits Productures d’Hydrocarbures (“BJSP”), for $4.6 million, increasing our total ownership in BJSP to 51%. L’Enterprise de Services aux Puits (“ENSP”), an indirect subsidiary of Sonatrach Petroleum Corp., owns the remaining 49%. BJSP provides coiled tubing, fracturing and cementing services to the Algerian market. Prior to obtaining controlling interest in BJSP, we accounted for the investment using the cost method, as we could not exercise significant influence over the entity. Following this transaction, which was accounted for

 

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as a step-acquisition, we have control of BJSP and consolidate the entity. In accordance with Accounting Principles Board (“APB”) 18, Equity Method of Accounting of Investments in Common Stock, and Accounting Research Bulletin (“ARB”) 51, Consolidated Financial Statements, in 2006, we retroactively adjusted beginning retained earnings to adopt the equity method of accounting for our ownership interest in previous periods. This adjustment resulted in an $8.3 million increase to beginning retained earnings. Following the transaction, the assets and liabilities and results of operations of BJSP are included in our consolidated results, in the International Pressure Pumping segment. The consolidation resulted in an increase of $42.4 million in total current assets (including approximately $14.1 million in cash), $12.1 million in total current liabilities, $19.3 million in minority interest and $0.2 million in goodwill.

On August 15, 2006, we purchased substantially all of the operating assets of Dyna Coil of South Texas, Ltd., Dyna Coil Injection Systems, Inc. and Dynochem, Ltd. (collectively, “Dyna-Coil”) for $61.7 million in cash. Dyna-Coil is focused on production optimization services, particularly the installation and service of capillary injection systems and associated products (production chemicals) mostly in the U.S. and Canada and is included in our chemical services business in the Oilfield Services Group segment. The acquisition resulted in an increase of $8.2 million in total current assets, $3.4 million in property and equipment, $7.1 million of technology based intangibles and $42.9 million in goodwill.

We are currently in the process of completing our review and determination of the fair values of the assets acquired from Norson and Allis-Chalmers. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. Pro forma financial information for our fiscal 2007 and fiscal 2006 acquisitions is not included as they were not material individually or in aggregate to our financial statements.

Results of Operations

Consolidated (in millions)

 

     2007    % Change     2006    % Change     2005

Revenue

   $ 4,802.4    10 %   $ 4,367.9    35 %   $ 3,243.2

Operating income

   $ 1,150.5    -2 %   $ 1,171.7    84 %   $ 637.1

Worldwide rig count(1)

     3,103    4 %     2,995    16 %     2,576

(1)

Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.

Results for fiscal 2007 compared to fiscal 2006

All of our reportable segments, except Canada, contributed to the increase in revenue for fiscal 2007 when compared to fiscal 2006. The increase primarily relates to higher activity in all major markets except Canada, where depressed market conditions were present throughout fiscal 2007. Worldwide average active drilling rigs for fiscal 2007 increased 4% compared to the prior year.

Fiscal 2007 consolidated operating income was 24%, a 2% decrease compared to fiscal 2006. Operating income margin was negatively impacted by a 68% decline in operating income from Canada as well as price reductions in the U.S. market.

Results for fiscal 2006 compared to fiscal 2005

Consolidated revenue in fiscal 2006 benefited from increased worldwide drilling activity and pricing improvements in the U.S., Canada, and Latin America. Revenue growth surpassed the increase exhibited by worldwide drilling activity during the same period.

 

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Consolidated operating income also experienced significant growth in fiscal 2006 as a result of the increased revenue described above. All of our business segments showed strong increases in operating income from the same period in the prior year. For fiscal 2006, consolidated operating income margins improved to 27% from 20% reported in fiscal 2005. These margin enhancements were largely due to higher revenue and improved pricing in the U.S. and Canada, in addition to equipment and labor efficiencies.

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

U.S./Mexico Pressure Pumping Segment (in millions)

 

     2007    % Change     2006    % Change     2005

Revenue

   $ 2,562.7    9 %   $ 2,353.8    40 %   $ 1,683.2

Operating income

   $ 881.6    -2 %   $ 899.2    71 %     524.9

U.S. rig count(1)

     1,749    10 %     1,587    20 %     1,323

Mexico rig count(1)

     90    6 %     85    -23 %     111

(1)

Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.

Results for fiscal 2007 compared to fiscal 2006

Fiscal 2007 U.S./Mexico revenue increased compared to the prior year as the result of activity increases most notably in East Texas, Permian Basin, and Northeast regions of the United States. The Mexico region also benefited from improved revenues attributable to the expansion of our business in southern Mexico. These increases were slightly offset by a decline in activity in the Pacific region. While the U.S./Mexico average active drilling rigs increased 10% for fiscal 2007, revenue was negatively impacted by lower prices received for our products and services stemming from competitive pressures in the market.

Operating income margin declined to 34% compared to 38% in the prior fiscal year, primarily due to lower pricing, increased material and labor costs and increased depreciation expense.

Results for fiscal 2006 compared to fiscal 2005

U.S./Mexico pressure pumping revenue increased as a result of increased drilling activity and improved pricing in the U.S. market. Operating regions providing the most revenue growth include the Permian Basin, East Texas, and Rocky Mountain areas. This was slightly offset by lower revenue in Mexico.

Activity: Every operating region within the U.S. experienced considerable revenue growth, due to a 20% increase in U.S. drilling activity from the same period in the prior year. The U.S. revenue improvement was partially offset by lower revenue in Mexico due to lower levels of drilling activity. The average rig count for Mexico decreased 23%, compared to the prior fiscal year.

Price: Price improvement in the U.S. was supported by three price book increases between May of 2005 and May 2006. A U.S. price book with a 15% average price increase was issued on May 1, 2005. Another price book was issued on November 1, 2005 averaging an 11% price increase. Finally, on May 1, 2006 the U.S. issued the latest price book increase. At September 30, 2006, 52% of customers were on the May 1, 2006 price book. The degree of acceptance for any price book increase described above varies by customer and depends on activity levels and competitive pressures.

The improvement in U.S./Mexico pressure pumping operating income was largely the result of the increase in U.S. revenue described above. U.S. pricing improvements increased operating income without any associated cost. In addition, operating income gained from labor efficiencies as activity increases occurred without a proportional increase in headcount. Average headcount increased 12% in fiscal 2006, with revenue increasing

 

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40%. Cost efficiencies were also obtained through utilization of newer, more efficient and more modern equipment. See “Business” included elsewhere in this Annual Report on Form 10-K for information on the U.S. fleet recapitalization initiative.

International Pressure Pumping Segment (in millions)

 

     2007    % Change     2006    % Change     2005

Revenue

   $ 1,074.7    21 %   $ 884.7    28 %   $ 693.5

Operating income

   $ 152.7    11 %   $ 138.1    78 %   $ 77.5

International rig count, excluding Mexico(1)

     899    10 %     820    13 %     723

(1)

Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.

Results for fiscal 2007 compared to fiscal 2006

 

     % change in Revenue  

Europe/Africa

   27 %

Middle East

   21 %

Asia Pacific

   28 %

Russia

   -5 %

Latin America

   21 %

All of our operating regions within International Pressure Pumping, except Russia, showed significant increases in revenue in fiscal 2007 compared to fiscal 2006.

Europe/Africa showed improvement as the result of the acquisition of BJSP in July 2006. We have acquired a controlling interest in BJSP and now consolidate its revenue. Excluding the impact from the BJSP acquisition, revenue in the region increased 10%. Activity related revenue increases in the Netherlands and expansion of operations into Libya also contributed to the region’s improvement from the prior year. These increases were slightly offset by lower coiled tubing revenue in Norway. The average active drilling rig count increased 8% compared to the prior fiscal year.

Despite a significant decline in revenue from the prior year’s non-repeat blowout work in Bangladesh, the Middle East showed improved revenues due to increased activity and the introduction of vessel operations in India and increased coiled tubing work in Saudi Arabia. The average active drilling rig count for fiscal 2007 increased 13% compared to fiscal year 2006.

The award of contracts in Malaysia and activity increases in Australia accounted for most of Asia Pacific’s revenue increase. This increase was offset by a decline in revenue from New Zealand due to non-repeat work in the prior fiscal year. The average active drilling rig count for fiscal 2007 increased 4% in Asia Pacific compared to fiscal year 2006.

Our Russian revenue declined as the result of the divesture of our workover rig business in the region in the second quarter of fiscal 2007 as well as lower margin performance activity. Excluding revenue from our workover rig business, revenue from the region increased 10% compared to the prior year.

Our Latin American region improvement was due primarily to increased activity in Argentina, Colombia, and Brazil. The average active drilling rig count increased 10% in Latin America compared to the prior year.

Operating income margin was 14% for fiscal 2007 compared to 16% in the prior year. Margin contributions from the Asia Pacific and Latin America were offset by margin declines from the high margin non-repeat blowout work in Bangladesh in the prior fiscal year and activity declines in Norway.

 

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Results for fiscal 2006 compared to fiscal 2005

The following table summarizes the change in revenue for fiscal 2006 compared to fiscal 2005 for each of the operating segments of International Pressure Pumping:

 

     % change in Revenue  

Europe/Africa

   29 %

Middle East

   29 %

Asia Pacific

   32 %

Russia

   5 %

Latin America

   31 %

All of our operating segments contributed to the revenue increase in fiscal 2006. Activity growth in Argentina, Venezuela, Columbia and Brazil as well as in other markets within the region led the Latin American revenue increase. Latin America’s revenue increase of 31% surpassed the average rig count increase of 16%. Middle East revenue increased largely due to strong rig activity in Kazakhstan and overall activity increases in Saudi Arabia. Average drilling activity for the Middle East increased 17%. These contributions were slightly affected by lower revenue due to the conclusion of Bangladesh blowout work in the prior year. Activity increases in the North Sea and Africa contributed to revenue improvement in Europe/Africa. New Zealand and Vietnam also added to the overall increase in revenue in fiscal 2006 for Asia Pacific. We acquired a controlling interest in BJSP and accordingly, began consolidating its revenue effective July 1, 2006. Excluding BJSP, revenue would have increased 24% in Europe/Africa.

Operating income increased as the result of improved revenues in Latin America and the Middle East as described above, as well as improved margins from Asia Pacific operations. Also contributing to the improved operating income were higher equipment utilization as well as labor efficiencies. Labor efficiencies were achieved through an increase in activity without a proportional increase in headcount, thereby increasing employee utilization per job. Headcount increased 7% compared to the same period in the prior year, while revenue increased 28%. Consequently, operating income margins improved to 16% from 11% for fiscal 2006 compared to the prior fiscal year.

Canada Pressure Pumping (in millions)

 

     2007    % Change     2006    % Change     2005

Revenue

   $ 386.5    -20 %   $ 481.4    38 %   $ 348.4

Operating income

   $ 32.5    -68 %   $ 102.1    75 %   $ 58.3

Canada rig count(1)

     365    -27 %     502    20 %     420

(1)

Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.

Results for fiscal 2007 compared to fiscal 2006

Lower activity levels influenced by lower natural gas prices caused revenue to decline compared to the prior year. Average active drilling rigs decreased 27% in fiscal 2007, with revenue exhibiting a corresponding decrease of 20%. The region has also experienced lower pricing for our products and services.

Operating income margin decreased to 8% from 21% in the prior year. Along with declining prices for our products and services, the region also had higher depreciation expense, material costs and labor costs during fiscal 2007.

Results for fiscal 2006 compared to fiscal 2005

Geographic expansion, price improvement and increased average rig count contributed to our revenue improvement in Canada. During fiscal 2006, we opened two new bases in active oil and gas producing areas in

 

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Canada. Compared to the same period in the prior year, Canadian operations generated a 38% increase in revenue with average active drilling rigs increasing 20%. As revenues are primarily denominated in Canadian Dollars, a weakening U.S. dollar, compared to the Canadian dollar, also improved revenue 10%.

Operating income improved as a result of the revenue increases described above, coupled with labor efficiencies. Headcount increased 10%, with revenue increasing 38%. While favorable foreign exchange rates in Canada increased revenue, they had minimal impact on operating income as most of our expenses are also denominated in Canadian dollars.

Oilfield Services Group (in millions)

 

     2007    % Change     2006    % Change     2005

Revenue

   $ 778.4    20 %   $ 648.0    25 %   $ 517.7

Operating income

     163.5    23 %     132.4    96 %     67.6

Results for fiscal 2007 compared to fiscal 2006

The following table summarizes the change in revenue for fiscal 2007 compared to fiscal 2006 for each of the operating segments of the Oilfield Services Group:

 

     % Change in Revenue  

Tubular Services

   30 %

Process and Pipeline Services

   21 %

Chemical Services

   39 %

Completion Tools

   28 %

Completion Fluids

   -5 %

All of our operating segments, except Completion Fluids, showed revenue improvement in fiscal 2007. Our Tubular Services’ revenue for fiscal 2007 increased largely due to international market expansion, while our Process and Pipeline Services benefited from increased activity in our U.K. and U.S. operations as well as the acquisition of Norson in March 2007. Excluding the impact of the Norson acquisition, Process and Pipeline Services revenue increased 15%. Chemical Services revenue increased largely due to the acquisitions of Dyna-Coil’s and Allis-Chalmers’ capillary string businesses. Excluding these acquisitions, Chemical Services revenue increased 12%. Our Completion Tools revenue improvement was due to international growth as well as increased domestic deepwater activity, while revenue from our Completion Fluids operations declined due to the closing of low margin operations in the U.K. and Norway in the previous year.

Fiscal 2007 operating income margin for the Oilfield Services Group was 21%, an increase from 20% reported in fiscal year 2006, with Tubular Services being the largest contributor to the increase.

Results for fiscal 2006 compared to fiscal 2005

The following table summarizes the change in revenue for fiscal 2006 compared to fiscal 2005 for each of the operating segments of the Oilfield Services Group:

 

     % Change in Revenue  

Tubular Services

   23 %

Process and Pipeline Services

   17 %

Chemical Services

   45 %

Completion Tools

   20 %

Completion Fluids

   32 %

 

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The increase in revenue in fiscal 2006 was largely due to contributions from Completion Fluids, Chemical Services, and Process and Pipeline Services. Overall activity increases, primarily in the U.S. and Canada, boosted Process and Pipeline Services revenue, while the Completion Fluids and Chemical Services revenue increase was more attributable to increased U.S. market activity.

Operating income margins for the Oilfield Services Group increased to 20% for fiscal 2006 compared to 13% for fiscal 2005, with the revenue increases described above being the primary contributor to the increase.

Outlook

As stated under “Market Conditions” above, our 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.

We expect a slight increase in fiscal 2008 revenue over fiscal 2007 revenue. Our U.S./Mexico Pressure Pumping revenue is expected to increase, but we also expect pricing pressures to continue in the U.S. market. In Canada, we expect a marginal increase in drilling activity and we expect spring break up levels to be less severe than those experienced in fiscal 2007. We will continue to focus on labor cost efficiencies as well as equipment utilization and monitoring of discretionary spending in North America.

Our International Pressure Pumping revenue is expected to increase in fiscal 2008. We have developed a number of strategies to address low-performing countries and we expect margin expansion in this segment throughout fiscal 2008.

Revenue from our Oilfield Services Group is expected to increase in fiscal 2008, as the divisions within this segment continue to expand into the international markets through our existing pressure pumping infrastructure.

Other Expenses

The following table sets forth our other operating expenses (in millions):

 

     2007    % of
Revenue
    2006    % of
Revenue
    2005    % of
Revenue
 

Research and engineering

   $ 67.5    1.4 %   $ 63.9    1.5 %   $ 54.2    1.7 %

Marketing expense

     107.4    2.2 %     103.3    2.4 %     92.3    2.8 %

General and administrative expense

     144.0    3.0 %     132.0    3.0 %     111.3    3.4 %

Research and engineering expense: While these expenses have decreased as a percent of revenue, the total of these expenses increased 6% for fiscal 2007 when compared to fiscal 2006. The increase mostly relates to increased personnel at our primary research facility in Tomball, Texas and certain operating locations to support higher activity.

The total of these expenses increased 18% for fiscal 2006, compared to fiscal 2005. The increase was due primarily to higher activity levels experienced throughout our business. However, each of these expenses were lower as a percent of revenue compared to the same periods in the prior fiscal year. This is due to our revenue increasing at a higher rate than expenses related to research and engineering.

Marketing expense: These expenses increased 4% for fiscal 2007 when compared to fiscal 2006 as the result of higher commissions in certain markets internationally as well as increased headcount to support market growth.

These expenses increased 12% for fiscal 2006, compared to fiscal 2005. The increase was largely due to higher activity levels experienced throughout our business in fiscal 2006.

General and administrative expense: While these expenses have remained consistent as a percent of revenue, they increased 9% for fiscal 2007 compared to fiscal 2006. The increase primarily relates to increased personnel and a stock based compensation expense increase of $7.6 million, offset by lower compensation

 

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expense related to annual performance incentive accruals. The decrease in annual performance incentive accruals is the primary reason for the decrease in Corporate expenses in fiscal 2007.

These expenses increased 19% in fiscal 2006, compared to 2005, due primarily to an overall increase in salaries and incentive expense caused by increased personnel. Average headcount in this area increased 9% compared to fiscal 2005. In addition, stock based compensation expense increased $2.5 million related to our adoption of Statement of Financial Accounting Standards (“SFAS”) 123(R) on October 1, 2005 (see Note 13 of the Notes to the Consolidated financial Statements).

The following table shows a comparison of interest expense, interest income, and other income (expense), net (in millions):

 

     2007     2006     2005  

Interest expense

   $ (32.7 )   $ (14.6 )   $ (11.0 )

Interest income

     1.6       14.9       11.3  

Other income (expense), net

     (6.6 )     —         16.0  

Interest Expense and Interest Income: Interest expense, net of capitalized interest, increased $18.1 million for fiscal 2007 compared to fiscal 2006 as the result of higher average outstanding debt during the respective periods. As a result of an increased average debt balance in addition to higher manufacturing levels, capitalized interest increased $6.0 million for fiscal 2007 compared to fiscal 2006.

The increase in interest expense of $3.6 million for fiscal 2006, compared to fiscal 2005, was due to our public offering of $500.0 million aggregate principal amount of Senior Notes in June 2006 as well as borrowing $160.0 million under our Revolving Credit Facility during the period. See “Liquidity and Capital Resources” below for further discussion of the debt issuance and the Revolving Credit Facility agreement.

Interest income decreased $13.3 million for fiscal 2007 compared fiscal 2006 as a result of a lower average cash and cash equivalents balance throughout the fiscal year.

Interest income increased $3.6 million in fiscal 2006, compared to the prior year, as a result of increased average cash and cash equivalents balances as well as favorable interest rates.

Other Income (Expense), net: The increase in other expense, net for fiscal 2007 consisted primarily of minority interest expense, due to the acquisition of controlling interest in BJSP during the third quarter of fiscal 2006.

In fiscal 2006, we received $2.8 million for the recovery of misappropriated funds, offset by other expenses. Other Income increased during fiscal 2005 due to recording a gain of $9.0 million relating to the recovery of misappropriated funds in the first quarter and $9.5 million recorded in the fourth quarter to reflect the reversal of excess accrued liabilities in the Asia Pacific region.

For additional information, see Note 12 of the Notes to the Consolidated Financial Statements.

Liquidity and Capital Resources

Historical Cash Flow

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

 

     2007     2006     2005  

Cash flow from operations

   $ 840.7     $ 832.5     $ 545.7  

Cash flow used in investing

     (777.9 )     (503.2 )     (86.2 )

Cash flow used in financing

     (98.0 )     (593.4 )     (527.8 )

Effect of exchange rate changes on cash

     1.0       —         —    
                        

Change in cash and cash equivalents

   $ (34.2 )   $ (264.1 )   $ (68.2 )

 

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Fiscal 2007

As a result of pricing pressures in North America during fiscal 2007, we experienced only a modest increase in cash flow from operations compared to fiscal 2006. Significant uses of cash included increased inventory in anticipation of increases in activity, increased accounts receivable as a result of increased revenue and days sales outstanding, and increased prepaid expenses primarily related to tax payments. Increased accounts payable also contributed to cash flow from operations, mostly from increased activity levels.

The cash flow used in investing during fiscal 2007 was almost entirely due to $752.1 million of purchases of property, plant, and equipment, including $47.8 million paid to buy-out an equipment partnership established in 1997. We also paid $57.9 million, net of cash, for acquisitions.

Cash flows used in financing consisted of $11.0 million, net, in proceeds from short term borrowings, $74.6 million in repurchases of our common stock and $58.6 million of dividend payments during fiscal 2007. We also received proceeds in the amount of $22.4 million from employee stock purchases and stock option exercises during fiscal 2007.

Fiscal 2006

Cash flow from operations increased principally as a result of increased activity levels. Our working capital decreased $139.8 million at September 30, 2006 compared to September 30, 2005. This was largely a result of utilizing our cash to repurchase treasury stock. Accounts receivable increased $215.0 million, inventory increased $111.2 million, and accounts payable increased $105.8 million primarily as a result of an increase in worldwide activity levels. Also as a result of increased activity, we increased the number of employees and therefore, our employee compensation and benefits liability increased $26.8 million.

The cash flow used in investing was almost entirely due to $460.0 million of purchases of property, plant, and equipment in fiscal 2006. We also paid $52.2 million in connection with two acquisitions (see Note 3 in the Notes to the Consolidated Financial Statements).

In fiscal 2006, we spent $1,133.3 million to repurchase 31.7 million shares of stock. During the year, cash flow from financing activities included proceeds from our additional long-term debt in the amount of $499.7 million in Senior Notes. These proceeds were primarily used to repurchase treasury stock. We also had $160.0 million in borrowings under our Revolving Credit Facility and paid dividends of $64.3 million.

Fiscal 2005

Our 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, we redeemed the outstanding Convertible Senior notes for $422.4 million thereby reducing cash and cash equivalents and current debt.

The cash flow provided by investing was primarily attributable to our 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 our common stock totaling $98.4 million and the payment of dividends in the amount of $51.9 million during fiscal 2005.

 

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Liquidity and Capital Resources

Cash flows from operations are expected to be our primary source of liquidity in fiscal 2008. Our sources of liquidity also include cash and cash equivalents of $58.2 million at September 30, 2007 and the available financing facilities listed below (in millions):

 

Financing Facility

   Expiration    Borrowings at
September 30, 2007
   Available at
September 30, 2007

Revolving Credit Facility

   August 2012    $ 147.0    $ 253.0

Discretionary

   Various times within the
next 12 months
   $ 24.3    $ 140.6

On June 8, 2006, we completed a public offering of $500.0 million aggregate principal amount of Senior Notes, consisting of $250.0 million of floating rate Senior Notes due 2008, with an annual interest rate of three-month LIBOR plus 17 basis points, and $250.0 million of 5.75% Senior Notes due 2011. The net proceeds from the offering of approximately $497.1 million, after deducting underwriting discounts and commissions and expenses, were used primarily to repurchase outstanding shares of common stock and also repay indebtedness, fund capital expenditures and for other corporate purposes. As of September 30, 2007, we had $250.0 million of the Senior Notes due 2008 issued and outstanding and $249.8 million, net of discount, of the 5.75% Senior Notes due 2011 issued and outstanding.

In August 2007, we amended and restated our then existing revolving credit facility. The amended and restated revolving credit facility (the “Revolving Credit Facility”) 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 August 2012. In addition, we have the right to request up to an additional $200 million over the permitted borrowings of $400 million, subject to the approval of our lenders at the time of the request. Interest on outstanding borrowings is charged based on prevailing market rates. We are 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 $0.3 million in fiscal 2007 and $0.5 million in fiscal 2006. 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 62.5%, though there were no material fees in fiscal 2007 or 2006. At September 30, 2007 and 2006, there was $147.0 million and $160.0 million, respectively, in outstanding borrowings under the Revolving Credit Facility.

In addition to the Revolving Credit Facility, we had $164.9 million of unsecured, discretionary lines of credit at September 30, 2007, 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 $24.3 million and $0.3 million in outstanding borrowings under these lines of credit at September 30, 2007 and 2006, respectively. The weighted average interest rates on short-term borrowings outstanding as of September 30, 2007 and 2006 were 5.40% and 5.95%, respectively.

Management believes that cash flows from operations combined with cash and cash equivalents, the Revolving Credit Facility and other discretionary credit facilities provide us with sufficient capital resources and liquidity to manage our 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, we expect to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

The Senior Notes and Revolving Credit Facility include various customary covenants and other provisions, including the maintenance of certain profitability and solvency ratios, none of which materially restrict our activities. We are currently in compliance with all covenants imposed.

 

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Cash Requirements

We anticipate capital expenditures to be approximately $640 million in fiscal 2008, compared to $704.3 million in fiscal 2007, excluding $47.8 million for the purchase of assets from an equipment partnership. The 2008 capital expenditure program is expected to consist primarily of capital for facilities, new pressure pumping equipment, new equipment for our Oilfield Services Group, and capital to extend the useful life of existing assets. In 1998, we embarked on a program to replace our aging U.S. fracturing pump fleet with new, more efficient and higher horsepower pressure pumping equipment. We have since expanded the U.S. fleet recapitalization initiative to include additional equipment, such as cementing, nitrogen and acidizing equipment and have made significant progress in adding new equipment. However, much of the older equipment still remains in operation due to the increases in market activity. We plan to continue adding new equipment to our fleet and the market activity level at the time the equipment is ready for use will determine if the new equipment will be used for expansion or used as replacement assets. At the end of fiscal 2007, approximately 20% of our U.S. fleet remained candidates for future replacement as part of our recapitalization initiative. The actual amount of fiscal 2008 capital expenditures will depend primarily on maintenance requirements and expansion opportunities and our ability to execute our budgeted capital expenditures.

In fiscal 2008, our minimum pension and postretirement funding requirements are anticipated to be approximately $19.0 million. We contributed $16.8 million during fiscal 2007.

We paid cash dividends in the amount of $.05 per common share on a quarterly basis in fiscal 2007, totaling $58.6 million. We anticipate paying a quarterly dividend in fiscal 2008; however, dividends are subject to approval of our Board of Directors each quarter and the Board has the ability to change the dividend policy at any time.

As of September 30, 2007, we had $250.0 million of Senior Notes due 2008 issued and outstanding and $249.8 million of 5.75% Senior Notes due 2011 issued and outstanding, net of discount (collectively “the Notes”). We intend to redeem the $250.0 million Senior Notes due 2008 with existing cash and if necessary, through funds available from our Revolving Credit Facility. We expect cash paid for net interest expense (net of interest income) to be approximately $26.3 million in fiscal 2008.

The following table summarizes our contractual obligations and other commercial commitments as of September 30, 2007 (in thousands):

 

Contractual Obligations

   Total    Less than
1 year
  

1-3

Years

   4-5
Years
   After 5
Years

Long term and short term debt

   $ 671,268    $ 421,268    $ 250,000    $ —      $ —  

Interest on long term debt and capital leases

     69,423      26,296      28,752      14,375      —  

Capital lease obligations

     2,949      867      1,146      936      —  

Operating leases

     174,956      46,703      73,716      51,634      2,904

Equipment financing arrangement(1)

     54,649      12,990      41,659      —        —  

Purchase obligations(2)

     392,576      388,576      4,000      —        —  

Purchase commitments(3)

     101,822      26,317      41,032      30,643      3,830

Other long-term liabilities(4)

     91,449      90,777      144      96      432
                                  

Total contractual cash obligations

   $ 1,554,092    $ 1,013,794    $ 440,449    $ 97,684    $ 7,166
                                  

(1)

As discussed below, we have the option, but not the obligation, to purchase the pumping service equipment in this partnership for approximately $32 million in 2010. Currently, we expect to purchase the pumping service equipment and have therefore included the option payment in the table above.

(2)

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

 

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(3)

We have entered into agreements with certain suppliers to ensure that a certain level of materials are maintained in the U.S. and Canada.

(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.

We expect that cash and cash equivalents and cash flows from operations will generate sufficient cash flows to fund all of the cash requirements described above.

Off Balance Sheet Transactions

In 1999, we contributed certain pumping service equipment to a limited partnership, in which we own a 1% interest. The equipment is used to provide services to our customers for which we pay 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. We assessed the terms of this agreement and determined it was a variable interest entity as defined in FIN 46, Consolidation of Variable Interest Entities. However, we were 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 $9.0 million and $16.1 million as of September 30, 2007 and September 30, 2006, 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. As a result of the substitutions, the deferred gain was reduced by $0.8 million in fiscal 2007 and $2.8 million in fiscal 2006. In September 2010, we have the option, but not the obligation, to purchase the pumping service equipment for approximately $32 million. We currently have the intent to exercise this option.

The option price to purchase the equipment under the partnership depends in part on the fair market value of the equipment held by the partnership at the time the option is exercised as well as other factors specified in the agreement.

In 1997, we contributed certain pumping service equipment to a limited partnership, in which we owned a 1% interest. The equipment was used to provide services to our customers for which we paid a service fee. On February 9, 2007, we purchased the remaining partnership interest for $47.8 million, and as a result acquired the partnership equipment. The acquisition of the partnership controlling interest was accounted for as an asset purchase.

Contractual Obligations

We routinely issue Parent Company Guarantees (“PCGs”) in connection with service contracts entered into by our subsidiaries. The issuance of these PCGs is frequently a condition of the bidding process imposed by our customers for work in countries outside of North America. The PCGs typically provide that we guarantee the performance of the services by our local subsidiary. The term of these PCGs varies with the length of the service contract. To date, the parent company has not been called upon to perform under any of these PCGs.

We arrange 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 we, or our subsidiary, have entered into with customers. The customer has the right to call on the bank guarantee, performance bond or standby letter of credit in the event that we, or our subsidiary, default in the performance of services. These instruments are required as a condition to 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

 

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of our 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 our other commercial commitments as of September 30, 2007 (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

   $ 53,346    $ 53,336    $ 10    $ —      $ —  

Guarantees

     193,392      81,567      65,595      15,658      30,572
                                  

Total Other Commercial Commitments

   $ 246,738    $ 134,903    $ 65,605    $ 15,658    $ 30,572
                                  

Investigations Regarding Misappropriation and Possible Illegal Payments

We are in discussions with the DOJ and SEC regarding our internal investigation and certain other matters described in Note 12 of the Notes to the Consolidated Financial Statements. 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 the foregoing may have on our consolidated financial statements.

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. We base our 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 our 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. We believe the following are the most critical accounting policies used in the preparation of our 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: We account for goodwill in accordance with SFAS 142, Goodwill and Other Intangible Assets. 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

 

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valuation technique based on multiples of earnings or revenue. The second step compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, 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. Our estimate of fair value is primarily determined using discounted cash flows. This approach uses significant assumptions such as a discount rate, growth rate, terminal value multiples, and rig count.

No impairment adjustment was necessary to our $963.9 million goodwill balance at September 30, 2007. See Note 11 of the Notes to the Consolidated Financial Statements for more information on goodwill.

Pension and Postretirement Benefit Plans: Pension expense is determined in accordance with the provisions of SFAS 87, Employers’ Accounting for Pensions and SFAS 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. We determine 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, we are 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 our 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 accordance with SFAS 158, we utilize an estimated long-term rate of return on plan assets and any difference from the actual return is the unrecognized gain/loss which is recognized as a component of other comprehensive income. Amounts recorded to other comprehensive income are amortized and recognized in net periodic pension expense in future periods.

In fiscal 2008, we will have a pension and postretirement funding requirement of $19.0 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 our pension plans.

In September 2006, we entered into an agreement to settle our obligation with respect to the U.S. defined benefit plan. Plan assets of approximately $72 million, plus our contribution of $1.5 million, were used to purchase an insurance contract that is being used to fund the benefits and settle the plan. The proposed settlement requires approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service to relieve us of primary responsibility for the pension benefit obligation. Once regulatory approval is obtained, which is expected in fiscal 2008, we will expense approximately $23.3 million in connection with the settlement. This consists of $7 million of prepaid pension cost and $16 million of loss currently recognized in other comprehensive income. By relieving us of our obligation, the expense that would have otherwise been recognized over the remaining plan life will be accelerated to the period in which approval is received.

Income Taxes: The effective income tax rates were 32.3%, 31.4%, and 30.7% for the years ended September 30, 2007, 2006, and 2005, 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.

 

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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 SFAS 5.

Self Insurance Accruals and Loss Contingencies: We are 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 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. 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 us 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. We record 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 February 2007, the FASB issued SFAS No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective the beginning of an entity’s first fiscal year beginning after November 15, 2007 and is to be applied prospectively, unless the entity elects early adoption. We are currently in the process of evaluating the impact of SFAS 159 on our financial statements, if we choose to elect this option.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), Fair Value Measurements, effective for financial statements issued for fiscal years beginning after November 15, 2007. SFAS 157 introduces a new definition of fair value, a fair value hierarchy (requiring market based assumptions be used, if available) and new disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. We are currently in the process of evaluating the impact of SFAS 157 on our financial statements.

In July 2006, the FASB issued Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition threshold

 

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and measurement attribute, as well as criteria for subsequently recognizing, derecognizing and measuring tax positions for financial statement purposes and requires companies to make disclosures about uncertain income tax positions, including a detailed rollforward of tax benefits taken that do not qualify for financial statement recognition. In addition, FIN 48 requires us to disclose the classification of interest and penalties related to uncertain tax positions. We record these as a component of income tax expense. We estimate the impact of adopting FIN 48 to be a reduction in retained earnings in the range of $6 million to $10 million.

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, our prospects, expected revenue, expenses and profits, developments and business strategies for our 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”, “should” and similar terms and phrases. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe 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,

 

   

our ability to expand our products and services (including those we acquire) 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 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 us,

 

   

competition and consolidation in our business,

 

   

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

 

   

other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission.

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 securities laws, we do 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.

 

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ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

The table below provides information about our market sensitive financial instruments and constitutes a “forward-looking statement.” Our major market risk exposure is to foreign currency fluctuations internationally and changing interest rates, primarily in the United States, Canada and Europe. Our 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, 2007, our combined interest expense to third parties would increase by a total of $197 thousand each month in which such increase continued. At September 30, 2007 and 2006, we had fixed-rate debt outstanding of $249.8 million and $249.7 million, net of discount, respectively. These instruments are fixed-rate and, therefore, do not expose us 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 $4.5 million if interest rates were to decline by 10% from their rates at September 30, 2007.

Periodically, we borrow funds which are denominated in foreign currencies, which exposes us to market risk associated with exchange rate movements. There were $15.4 million and $0.3 million borrowings denominated in foreign currencies at September 30, 2007 and 2006, respectively. When management believes prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. There were no such forward foreign exchange contracts at September 30, 2007. The expected maturity dates and fair value of our market risk sensitive instruments are stated below (in millions). All items described are non-trading and are stated in U.S. dollars.

 

     Expected Maturity Dates   

Fair Value

9/30/07

     2008    2009    2010    2011    2012    Thereafter    Total   

SHORT-TERM BORROWINGS

                       

Bank borrowings; U.S.

                       

$ denominated—average rate 5.40%

   $ 24.3                   $ 24.3    $ 24.3

Revolving Credit Facility—Average rate 5.44%

     147.0                     147.0      147.0

LONG-TERM BORROWINGS

                       

Floating rate Senior Notes due 2008—Average rate 5.75%

     250.0                     250.0      248.1

5.75% Senior Notes due 2011

              249.8            249.8      253.9
                                                       

Total

   $ 421.3    $ —      $ —      $ 249.8    $ —      $ —      $ 671.1    $ 673.3
                                                       

 

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ITEM 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

We are 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). Our internal controls are 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 our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our internal control over financial reporting as of September 30, 2007 as required by the Securities and Exchange Act of 1934 Rule 13a-15(c). In making its assessment, we have utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. We concluded that based on our evaluation, our internal control over financial reporting was effective as of September 30, 2007.

The effectiveness of our internal control over financial reporting as of September 30, 2007 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/    JEFFREY E. SMITH        
J.W. Stewart     Jeffrey E. Smith
President and Chief Executive Officer     Senior Vice President and Chief Financial Officer

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of BJ Services Company:

We have audited the internal control over financial reporting of BJ Services Company and subsidiaries (the “Company”) as of September 30, 2007, 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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2007, 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, 2007 of the Company and our report dated November 29, 2007 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

November 29, 2007

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and 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, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2007, 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 Company’s internal control over financial reporting as of September 30, 2007, 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 November 29, 2007 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

November 29, 2007

 

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BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF OPERATIONS

 

     Year Ended September 30,  
     2007     2006     2005  
     (in thousands, except per share amounts)  

Revenue

   $ 4,802,409     $ 4,367,864     $ 3,243,186  

Operating expenses:

      

Cost of sales and services

     3,332,620       2,895,749       2,334,198  

Research and engineering

     67,536       63,875       54,197  

Marketing

     107,421       103,319       92,255  

General and administrative

     143,992       132,011       111,285  

Loss on long-lived assets

     301       1,174       14,192  
                        

Total operating expenses

     3,651,870       3,196,128       2,606,127  
                        

Operating income

     1,150,539       1,171,736       637,059  

Interest expense

     (32,731 )     (14,558 )     (10,951 )

Interest income

     1,624       14,916       11,281  

Other (expense) income, net

     (6,584 )     (11 )     15,958  
                        

Income before income taxes

     1,112,848       1,172,083       653,347  

Income tax expense

     359,208       367,473       200,305  
                        

Net income

   $ 753,640     $ 804,610     $ 453,042  
                        

Earnings per share:

      

Basic

   $ 2.57     $ 2.55     $ 1.40  

Diluted

   $ 2.55     $ 2.52     $ 1.38  

Weighted average shares outstanding:

      

Basic

     292,757       315,022       323,763  

Diluted

     295,916       318,820       329,115  

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

 

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BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

ASSETS

 

     As of September 30,
     2007    2006
     (in thousands)

Current assets:

     

Cash and cash equivalents

   $ 58,199    $ 92,445

Receivables, less allowance for doubtful accounts: 2007, $20,550; 2006, $18,976

     1,022,847      927,027

Inventories:

     

Products

     226,666      185,249

Work-in-progress

     37,460      27,308

Parts

     221,811      143,347
             

Total inventories

     485,937      355,904

Deferred income taxes

     19,994      5,103

Prepaid expenses

     72,033      36,311

Other current assets

     44,762      42,070
             

Total current assets

     1,703,772      1,458,860

Property:

     

Land

     29,180      26,573

Buildings and other

     359,735      317,337

Machinery and equipment

     2,947,473      2,232,240
             

Total property

     3,336,388      2,576,150

Less accumulated depreciation

     1,370,669      1,183,224
             

Property, net

     1,965,719      1,392,926

Goodwill

     963,937      928,297

Deferred income taxes

     30,471      29,557

Investments and other assets

     51,313      52,648
             

Total assets

   $ 4,715,212    $ 3,862,288
             

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

 

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BJ SERVICES COMPANY

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

     As of September 30,  
     2007     2006  
     (in thousands, except shares)  

Current liabilities:

    

Accounts payable, trade

   $ 530,029     $ 435,040  

Short-term borrowings

     171,268       160,274  

Current portion of long-term debt

     250,000       —    

Accrued employee compensation and benefits

     124,231       131,725  

Income taxes

     51,829       60,160  

Taxes other than income

     37,282       25,385  

Accrued insurance

     26,284       21,965  

Other accrued liabilities

     122,265       113,387  
                

Total current liabilities

     1,313,188       947,936  

Long-term debt

     249,760       499,694  

Deferred income taxes

     95,485       66,584  

Accrued postretirement benefits

     57,504       54,296  

Other long-term liabilities

     147,877       146,838  

Commitments and contingencies (Note 10)

    

Stockholders’ equity:

    

Preferred stock (authorized 5,000,000 shares, none issued)

    

Common stock, $.10 par value (authorized 910,000,000 shares; 347,510,648 shares issued and 291,735,636 outstanding in 2007; 347,510,648 shares issued and 293,193,764 outstanding in 2006)

     34,752       34,752  

Capital in excess of par

     1,060,115       1,028,813  

Retained earnings

     3,183,922       2,494,350  

Accumulated other comprehensive income

     51,644       22,833  

Treasury stock, at cost (2007 – 55,775,012 shares; 2006 – 54,316,884 shares)

     (1,479,035 )     (1,433,808 )
                

Total stockholders’ equity

     2,851,398       2,146,940  
                

Total liabilities and stockholders’ equity

   $ 4,715,212     $ 3,862,288  
                

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

 

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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
Compe-
nsation
    Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
    Total  

Balance, September 30, 2004

  323,738     $ 34,752   $ 994,724     $ (268,410 )   $ (6,961 )   $ 1,349,227     $ (908 )   $ 2,102,424  

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  

Dividends 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  

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 )   $ 1,747,445     $ 24,371     $ 2,492,041  

Comprehensive income:

               

Net income

              804,610      

Other comprehensive income, net of tax:

               

Cumulative translation adjustments

                9,511    

Minimum pension liability adjustment

                (11,049 )  

Comprehensive income

                  803,072  

Dividends declared

              (63,272 )       (63,272 )

Treasury stock purchase

  (31,726 )         (1,133,313 )           (1,133,313 )

Reissuance of treasury stock for:

               

Stock option plan

  911           13,180         454         13,634  

Stock purchase plan

  572           7,635         5,113         12,748  

Director stock award

  26         (355 )     355             —    

Stock based compensation

        21,397               21,397  

Adoption of SFAS 123(R) (Note 13)

        (9,195 )       9,195           —    

Tax benefit from exercise of options

        633               633  
                                                           

Balance, September 30, 2006

  293,194     $ 34,752   $ 1,028,813     $ (1,433,808 )   $ —       $ 2,494,350     $ 22,833     $ 2,146,940  

Comprehensive income:

               

Net income

              753,640      

Other comprehensive income, net of tax:

               

Cumulative translation adjustments

                40,551    

Minimum pension liability adjustment

                3,272    

Comprehensive income

                  797,463  

Adoption of SFAS 158, net of tax (Note 9)

                (15,012 )     (15,012 )

Dividends declared

              (57,362 )       (57,362 )

Treasury stock purchase

  (2,565 )         (74,597 )           (74,597 )

Reissuance of treasury stock for:    

                  —    

Stock option plan

  528           14,019         (6,300 )       7,719  

Stock purchase plan

  488           12,916         (406 )       12,510  

Director stock award

  43         (1,127 )     1,127             —    

Bonus stock award

  48         (1,308 )     1,308             —    

Stock based compensation

        31,625               31,625  

Tax benefit from exercise of options

        2,112               2,112  
                                                           

Balance, September 30, 2007

  291,736     $ 34,752   $ 1,060,115     $ (1,479,035 )   $ —       $ 3,183,922     $ 51,644     $ 2,851,398  
                                                           

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

 

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BJ SERVICES COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Year Ended September 30,  
     2007     2006     2005  
     (in thousands)  

Cash flows from operating activities:

      

Net income

   $ 753,640     $ 804,610     $ 453,042  

Adjustments to reconcile net income to cash provided from operating activities:

      

Depreciation

     209,019       166,763       136,861  

Net loss on long-lived assets

     301       1,174       14,192  

Excess tax benefits from stock compensation

     (1,812 )     (3,419 )     —    

Recognition of unearned compensation

     —         —         8,681  

Deferred income tax expense (benefit)

     17,472       6,024       (7,111 )

Minority interest expense

     11,315       3,970       3,725  

Changes in:

      

Receivables

     (97,355 )     (215,020 )     (154,677 )

Inventories

     (129,387 )     (111,189 )     (53,161 )

Prepaid expenses

     (35,950 )     (14,712 )     (453 )

Accounts payable, trade

     99,375       105,833       81,756  

Employee compensation and benefits

     (7,494 )     26,763       26,913  

Current income tax

     (8,561 )     34,726       (7,611 )

Other current assets

     1,909       (20,561 )     12,456  

Other current liabilities

     22,430       17,612       (979 )

Other, net

     5,755       29,880       32,071  
                        

Net cash flows provided from operating activities

     840,657       832,454       545,705  

Cash flows from investing activities:

      

Property additions

     (752,113 )     (459,974 )     (323,763 )

Proceeds from disposal of assets

     32,143       8,932       7,834  

Proceeds of U.S. Treasury securities

     —         —         229,774  

Acquisitions of businesses, net of cash acquired

     (57,920 )     (52,172 )     —    
                        

Net cash used for investing activities

     (777,890 )     (503,214 )     (86,155 )

Cash flows from financing activities:

      

Proceeds from exercise of stock options and stock purchase plan

     22,388       26,142       45,165  

Purchase treasury stock

     (74,597 )     (1,133,313 )     (98,360 )

Proceeds from long-term debt

     —         499,673       —    

Repayment of long-term debt

     —         (79,000 )     (422,369 )

(Repayment) proceeds of short-term borrowings, net

     10,994       156,884       (364 )

Dividends paid to shareholders

     (58,630 )     (64,338 )     (51,855 )

Excess tax benefits from stock compensation

     1,812       3,419       —    

Debt issuance costs

     —         (2,824 )     —    
                        

Net cash flows used in financing activities

     (98,033 )     (593,357 )     (527,783 )

Effect of exchange rate changes on cash

     1,020       54       16  

Decrease in cash and cash equivalents

     (34,246 )     (264,063 )     (68,217 )

Cash and cash equivalents at beginning of year

     92,445       356,508       424,725  
                        

Cash and cash equivalents at end of year

   $ 58,199     $ 92,445     $ 356,508  
                        

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

 

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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 founded in 1872, was organized in 1990 under the corporate laws of the state of Delaware. We are a leading worldwide provider of pressure pumping and other oilfield services for the petroleum industry. Our 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. The Oilfield Services Group includes 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 chemical services.

We consolidate 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 our ownership interest ranges from 20% to 50%, and we exercise 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 us 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.

Certain amounts for 2006 and 2005 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: We consider all highly liquid investments purchased with original maturities of three months or less at the time of purchase to be cash equivalents.

Allowance for doubtful accounts: We perform ongoing credit evaluations of our customers and adjust 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 receivables. 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.

Inventories: Inventories, which consist principally of (i) products which are consumed in our 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. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory based primarily on our estimated forecast of product demand, market conditions, production requirements and technological developments. Significant or unanticipated changes in market condition or to our forecast could require additional provisions for excess or obsolete inventory.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

Property: Property is stated at cost less amounts provided for permanent impairments and includes capitalized interest of $8.0 million, $2.0 million, and $1.2 million for the years ended September 30, 2007, 2006 and 2005, respectively. 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. We make 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 asset exceeds fair value. Fair value determination requires us to make long-term forecasts of future revenue and costs related to the assets subject to review. These forecasts require assumptions about demand for our products and services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Worldwide average active drilling rigs has experienced continued growth over the last three years. As such, substantially all of our equipment that can perform is currently working. In fiscal 2005, it was determined that certain equipment that was not able to operate and was maintained by Corporate personnel in our idle asset yard 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 the same or similar assets. We recorded an $11.7 million impairment during our fourth fiscal quarter of 2005 related to idle assets. This impairment is reflected in loss on long-lived assets in the Consolidated Statement of Operations and within Corporate in our segment footnote disclosure.

Intangible assets: Goodwill represents the excess of cost over the fair value of the net assets of companies acquired in purchase transactions. We account for goodwill in accordance with Statement of Financial Accounting Standards (“SFAS”) 142, Goodwill and Other Intangible Assets, which requires goodwill to be reviewed by reporting unit for possible impairment on an annual basis, or if circumstances indicate that impairment may exist. In determining our reporting units we considered the way we manage our operations and the nature of those operations. Our reporting units are our operating segments (see Note 8). We performed our annual evaluation as of September 30 and concluded that an impairment adjustment was not necessary to our goodwill balance at September 30, 2007 and 2006, respectively. Other intangible assets primarily consist of technology based intangible assets and are being amortized on a straight-line basis ranging from 5 to 20 years, with the weighted average amortization period being 14.8 years. We utilize undiscounted estimated cash flows to evaluate any possible impairment of intangible assets. The discount rate utilized is based on market factors at the time the loss is determined.

Income Taxes: We provide for income taxes in accordance with SFAS 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 us 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. We record a valuation allowance to reduce our deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be utilized. 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

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

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 SFAS 5, Accounting for Contingencies.

Self Insurance Accruals: We are 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. Our 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 5. 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 reasonably estimated. Accounting for contingencies such as environmental, legal, and income tax matters requires us to use judgment. 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 adversely impacted. For significant litigation, we accrue for our 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 we are primarily responsible for the remediation, our estimate 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 we have been identified as a potentially responsible party in a U.S. federal or state Superfund site, we accrue our share of the estimated remediation costs of the site based on the ratio of the estimated volume of waste contributed to the site by us to the total estimated volume of waste at the site.

Revenue Recognition: Our 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. We recognize 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.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

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: Our 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 in other comprehensive income. Our operations in Canada, Hungary and Algeria use their respective local currencies as the functional currency.

Derivative instruments: We occasionally enter 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 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that we recognize all derivatives on the balance sheet at fair value. We record derivative transactions in accordance with SFAS 133. No such contracts were outstanding as of September 30, 2007 or 2006.

Employee stock-based compensation: Employee services received in exchange for stock are expensed in accordance with SFAS 123(R), Share-Based Payment. The fair value of the employee services received in exchange for stock is measured based on the grant-date fair value which is determined using the Black-Scholes option-pricing model for the stock option awards, bonus stock and phantom stock and a Monte-Carlo simulation model for the stock incentive awards. Awards granted are expensed ratably over the vesting period of the award, unless retirement age is reached in which case the expense is accelerated. We reduce the expense recognized based on an estimated forfeiture rate at the time of grant and revise this rate, if necessary, in subsequent periods to reflect actual forfeitures. Excess tax benefits, as defined by SFAS 123(R), are recognized as an addition to capital in excess of par.

New accounting pronouncements: In February 2007, the FASB issued SFAS No. 159 (“SFAS 159”), The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115. This Statement provides companies with an option to report selected financial assets and liabilities at fair value. Under SFAS 159, companies that elect the fair value option will report unrealized gains and losses in earnings at each subsequent reporting date. In addition, SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The fair value option election is irrevocable, unless a new election date occurs. SFAS 159 is effective the beginning of an entity’s first fiscal year beginning after November 15, 2007 and is to be applied prospectively, unless the entity elects early adoption. We are currently in the process of evaluating the impact of SFAS 159 on our financial statements, if we choose to elect this option.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), Fair Value Measurements, effective for financial statements issued for fiscal years beginning after November 15, 2007. SFAS 157 introduces a new definition of fair value, a fair value hierarchy (requiring market based assumptions be used, if available) and new disclosures of assets and liabilities measured at fair value based on their level in the hierarchy. We are currently in the process of evaluating the impact of SFAS 157 on our financial statements.

In July 2006, the FASB issued Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition threshold and measurement attribute, as well as criteria for subsequently recognizing, derecognizing and measuring tax positions for financial statement purposes and requires companies to make disclosures about uncertain income tax positions, including a detailed rollforward of tax benefits taken that do not qualify for financial statement recognition. In addition, FIN 48 requires us to disclose the classification of interest and penalties related to uncertain tax positions. We record these as a component of income tax expense. We estimate the impact of adopting FIN 48 to be a reduction in retained earnings in the range of $6 million to $10 million.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

3. Acquisitions of Businesses

Fiscal 2007

On November 3, 2006, we completed the acquisition of Profile International Ltd. (“Profile”) for a total purchase price of $2.5 million, which resulted in $2.2 million of goodwill. Profile, located in Newcastle, England, provides caliper inspection tools for pipeline integrity assessment to markets worldwide. This business complements our pipeline inspection business in the Oilfield Services Group segment.

On December 20, 2006, we purchased substantially all of the operating assets of Tekcor Technology, Ltd. (“Tekcor”) for $8.3 million, which resulted in an increase of $3.6 million to total current assets, $0.7 million in property and equipment and $4.0 million to technology based intangible assets. Tekcor provides specialty chemicals and related services to the oil and gas well drilling industry. Located in Houston, Texas, Tekcor services markets along the Texas and Louisiana Gulf Coast and is included in our completion fluids business in the Oilfield Services Group segment.

On March 1, 2007 we acquired Aberdeen-based Norson Services Ltd, (“Norson”), a division of Norson Group Ltd., and substantially all of the assets of Norson Group’s United States subsidiary Norson Services LLC. The total purchase price paid for both acquisitions was $29.0 million, including legal fees, which resulted in an increase of $7.4 million in total current assets, $5.9 million in property and equipment, $1.8 million in intangible assets, $5.4 million in current liabilities, and $19.3 million of goodwill. The acquisition strengthens our service capabilities with the addition of Norson’s hydraulic and electrical umbilical testing services and the services provided by the Norson’s subsea units, which include remote pigging and flooding, subsea hydro testing and subsea data logging. This business complements our process and pipeline business in the Oilfield Services Group segment.

On June 30, 2007, we completed the acquisition of substantially all of the capillary tubing assets of Allis-Chalmers for a total purchase price of $16.3 million, which resulted in an increase of $1.5 million in current assets, $1.8 million in property and equipment, and $13.0 million of goodwill. The assets are used for the installation and service of capillary injection systems primarily in the U.S. and Mexico. The assets complement our Dyna-Coil acquisition which occurred in the fourth quarter of fiscal 2006 and will enhance our chemical services operation in the Oilfield Services Group segment.

Fiscal 2006

On June 25, 2006, we acquired an additional 2% interest in our Algerian joint venture, Societe Algerienne de Stimulation de Puits Productures d’Hydrocarbures (“BJSP”), for $4.6 million, increasing our total ownership in BJSP to 51%. L’Enterprise de Services aux Puits (“ENSP”), an indirect subsidiary of Sonatrach Petroleum Corp., owns the remaining 49%. BJSP provides coiled tubing, fracturing and cementing services to the Algerian market. Prior to obtaining controlling interest in BJSP, we accounted for the investment using the cost method, as we could not exercise significant influence over the entity. Following this transaction, which was accounted for as a step-acquisition, we have control of BJSP and consolidate the entity. In accordance with Accounting Principles Board (“APB”) 18, Equity Method of Accounting of Investments in Common Stock, and Accounting Research Bulletin (“ARB”) 51, Consolidated Financial Statements, in 2006, we retroactively adjusted beginning retained earnings to adopt the equity method of accounting for our ownership interest in previous periods. This adjustment resulted in an $8.3 million increase to beginning retained earnings. Following the transaction, the assets and liabilities and results of operations of BJSP are included in our consolidated results, in the International Pressure Pumping segment. The consolidation resulted in an increase of $42.4 million in total current assets (including approximately $14.1 million in cash), $12.1 million in total current liabilities, $19.3 million in minority interest and $0.2 million in goodwill.

On August 15, 2006, we purchased substantially all of the operating assets of Dyna Coil of South Texas, Ltd., Dyna Coil Injection Systems, Inc. and Dynochem, Ltd. (collectively, “Dyna-Coil”) for $61.7 million in

 

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Notes to the Consolidated Financial Statements—(Continued)

 

cash. Dyna-Coil is focused on production optimization services, particularly the installation and service of capillary injection systems and associated products (production chemicals) mostly in the U.S. and Canada and is included in our chemical services business in the Oilfield Services Group segment. The acquisition resulted in an increase of $8.2 million in total current assets, $3.4 million in property and equipment, $7.1 million of technology based intangibles and $42.9 million in goodwill.

We are currently in the process of completing our review and determination of the fair values of the assets acquired from Norson and Allis-Chalmers. Accordingly, allocation of the purchase price is subject to revision based on final determination of the asset values. Pro forma financial information for our fiscal 2007 and fiscal 2006 acquisitions is not included as they were not material individually or in aggregate to our financial statements.

4. Earnings Per Share

Basic EPS excludes dilution and is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted EPS is based on the weighted-average number of shares outstanding during each period and the assumed exercise of dilutive instruments (stock options, employee stock purchase plan, stock incentive awards, and director stock awards) less the number of treasury shares assumed to be purchased with the exercise proceeds using the average market price of our common stock for each of the periods presented.

The following table presents information necessary to calculate earnings per share for the three years ended September 30, 2007 (in thousands, except per share amounts):

 

     2007    2006    2005

Net Income

   $ 753,640    $ 804,610    $ 453,042

Weighted-average common shares outstanding

     292,757      315,022      323,763
                    

Basic earnings per share

   $ 2.57    $ 2.55    $ 1.40
                    

Weighted-average common and dilutive potential common shares outstanding:

        

Weighted-average common shares outstanding

     292,757      315,022      323,763

Assumed exercise of stock options(1)

     3,159      3,798      5,352
                    

Weighted-average dilutive shares outstanding

     295,916      318,820      329,115
                    

Diluted earnings per share

   $ 2.55    $ 2.52    $ 1.38
                    

(1)

For the year ended September 30, 2007, 2.9 million stock options were excluded from the computation of diluted earnings per share due to their antidilutive effect. There were no stock options excluded from the computation of diluted earnings per share due to their antidilutive effect for the years ended September 30, 2006 and 2005.

5. Debt

Long term debt at September 30 consisted of the following (in thousands):

 

     2007    2006

Floating rate Senior Notes due 2008

   $ 250,000    $ 250,000

5.75% Senior Notes due 2011, net of discount

     249,760      249,694
             
     499,760      499,694

Less current maturities of long-term debt

     250,000      —  
             

Long term debt

   $ 249,760    $ 499,694
             

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

On June 8, 2006, we completed a public offering of $500.0 million aggregate principal amount of Senior Notes, consisting of $250.0 million of floating rate Senior Notes due 2008, with an annual interest rate of three-month LIBOR plus 17 basis points, and $250.0 million of 5.75% Senior Notes due 2011. The net proceeds from the offering of approximately $497.1 million, after deducting underwriting discounts and commissions and expenses, were used primarily to repurchase outstanding shares of common stock and also repay indebtedness, fund capital expenditures and for other corporate purposes. As of September 30, 2007, we had $250.0 million of the Senior Notes due 2008 issued and outstanding and $249.8 million, net of discount, of the 5.75% Senior Notes due 2011 issued and outstanding. We intend to redeem the $250.0 million Senior Notes due 2008 with existing cash and if necessary, through funds available from our Revolving Credit Facility.

In August 2007, we amended and restated our then existing revolving credit facility. The amended and restated revolving credit facility (the “Revolving Credit Facility”) 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 August 2012. In addition, we have the right to request up to an additional $200 million over the permitted borrowings of $400 million, subject to the approval of our lenders at the time of the request. Interest on outstanding borrowings is charged based on prevailing market rates. We are 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 $0.3 million in fiscal 2007 and $0.5 million in fiscal 2006. 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 62.5%, though there were no material fees in fiscal 2007 or 2006. At September 30, 2007 and 2006, there was $147.0 million and $160.0 million, respectively, in outstanding borrowings under the Revolving Credit Facility.

In addition to the Revolving Credit Facility, we had $164.9 million of unsecured, discretionary lines of credit at September 30, 2007, 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 $24.3 million and $0.3 million in outstanding borrowings under these lines of credit at September 30, 2007 and 2006, respectively. The weighted average interest rates on short-term borrowings outstanding as of September 30, 2007 and 2006 were 5.40% and 5.95%, respectively.

Management believes that cash flows from operations combined with cash and cash equivalents, the Revolving Credit Facility and other discretionary credit facilities provide us with sufficient capital resources and liquidity to manage our 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, we expect to refinance this debt by arranging additional committed bank facilities or through other long-term borrowing alternatives.

The Senior Notes and Revolving Credit Facility include various customary covenants and other provisions, including the maintenance of certain profitability and solvency ratios, none of which materially restrict our activities. We are currently in compliance with all covenants imposed.

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 and Short-Term Borrowings: The carrying amount approximates fair value because of the short maturity of those instruments.

 

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Notes to the Consolidated Financial Statements—(Continued)

 

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

Foreign Currency Debt: Periodically, we borrow funds which are denominated in foreign currencies, which exposes us to market risk associated with exchange rate movements. There were $15.4 million borrowings denominated in foreign currencies at September 30, 2007 and $0.3 million borrowings at September 30, 2006.

The fair value of financial instruments that differed from their carrying value at September 30, 2007 and 2006 was as follows (in thousands):

 

     2007    2006
     Carrying
Amount
  

Fair

Value

   Carrying
Amount
  

Fair

Value

Floating rate Senior Notes due 2008

   $ 250,000    $ 248,120    $ 250,000    $ 249,990

5.75% Senior Notes due 2011

     249,760      253,900      249,694      253,543

7. Income Taxes

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

 

     2007    2006    2005

United States

   $ 831,852    $ 848,586    $ 425,399

Foreign

     280,996      323,497      227,948
                    

Income before income taxes

   $ 1,112,848    $ 1,172,083    $ 653,347
                    

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

 

     2007    2006     2005  

Current:

       

United States—Federal

   $ 260,374    $ 267,287     $ 125,209  

United States—State

     21,680      14,292       4,879  

Foreign

     59,682      79,870       77,328  
                       

Total current

     341,736      361,449       207,416  

Deferred:

       

United States—Federal

     5,069      7,363       8,696  

United States—State

     1,258      900       891  

Foreign

     11,145      (2,239 )     (16,698 )
                       

Total deferred

     17,472      6,024       (7,111 )
                       

Income tax expense

   $ 359,208    $ 367,473     $ 200,305  
                       

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

The consolidated effective income tax rates (as a percent of income (loss) before income taxes) for the three years ended September 30, 2007 varied from the United States statutory income tax rate for the reasons set forth below:

 

     2007     2006     2005  

Statutory rate

   35.0 %   35.0 %   35.0 %

Foreign earnings at varying rates

   (2.9 )   (2.9 )   (3.6 )

State income taxes, net of federal benefit

   1.3     0.8     0.6  

Other income taxes

   1.0     0.7     1.1  

Changes in valuation allowance

   (0.8 )   0.3     0.5  

Foreign income recognized domestically

   —       6.9     9.7  

Foreign expense recognized domestically

   —       (1.4 )   —    

Dividends received deduction

   —       (1.7 )   —    

Domestic production activity

   (0.7 )   (0.7 )   —    

Tax credits

   (1.0 )   (5.9 )   (12.3 )

Nondeductible expenses

   1.0     0.8     0.5  

Other, net

   (0.6 )   (0.5 )   (0.8 )
                  
   32.3 %   31.4 %   30.7 %
                  

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 we have 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 purposes. Deferred tax assets and liabilities as of September 30 were as follows (in thousands):

 

     2007     2006  

Assets:

    

Accrued compensation expense

   $ 24,309     $ 11,333  

Accrued postretirement benefits

     21,356       19,882  

Pension liability

     17,254       14,042  

Deferred gain(1)

     5,029       6,467  

Accrued insurance expense

     9,307       7,790  

Other accrued expenses

     24,651       28,737  

Foreign tax credit carryforwards

     21,375       37,211  

Net operating and capital loss carryforwards

     28,842       18,934  

Valuation allowance

     (32,012 )     (45,013 )
                

Total deferred tax asset

   $ 120,111     $ 99,383  
                

Liabilities

    

Differences in depreciable basis of property

   $ (144,407 )   $ (111,992 )

Unrealized gain/loss

     (10,387 )     (8,771 )

Pension asset

     (2,639 )     (8,526 )

Earnings of foreign affiliates

     (2,345 )     (2,345 )

Income accrued for financial reporting purposes, not yet reported for tax

     (5,583 )     —    
                

Total deferred tax liability

     (165,361 )     (131,634 )
                

Net deferred tax liability

   $ (45,250 )   $ (32,251 )
                

(1)

Deferred gain on the contribution of pumping service equipment to the partnership referred to in Note 10.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

At September 30, 2007, we had approximately $96.6 million of foreign net operating loss carryforwards and $2.4 million of state net operating loss carryforwards. The foreign net operating loss carryforwards expire as follows: $7.6 million by fiscal year 2016 and the remaining $89.0 million does not expire. The state net operating losses will expire between fiscal year 2008 and fiscal year 2018. We also had $21.4 million of U.S. foreign tax credit carryforwards, substantially all which expire in 2012. The tax impact of the net operating loss and foreign tax credit carryforwards that are more likely than not to expire before realization of the benefit is reflected in the valuation allowance balance as of September 30, 2007.

We record a valuation allowance to reduce our 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. Because management believes that it is more likely than not that a portion of the foreign net operating loss carry forwards and the U.S. foreign tax credits will not be realized, a valuation allowance has been recorded on these amounts. Furthermore, with respect to this valuation allowance, approximately $2.8 million of such valuation allowance, if subsequently realized, will be allocated to reduce goodwill.

Our stock basis difference in foreign subsidiaries, for which a U.S. deferred tax liability has not been established, is approximately $379.6 million as of September 30, 2007. This stock basis difference arises from the existence of unremitted foreign earnings and cumulative translation adjustments. We have provided additional taxes for the anticipated repatriation of foreign earnings of our foreign subsidiaries where we have 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 we 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 $32.7 million would be necessary.

8. Segment Information

We currently have 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 four reportable segments: U.S./Mexico Pressure Pumping, International Pressure Pumping, Canada Pressure Pumping and the Oilfield Services Group.

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 five operating segments. Similar to U.S./Mexico Pressure Pumping, it includes cementing and stimulation services. These services are provided to customers in more than 50 countries in the major international oil and natural gas producing areas of Latin America, Europe and Africa, Asia Pacific, Russia and the Middle East. These 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.

Canada Pressure Pumping segment has one operating segment. Like International and U.S./Mexico Pressure Pumping, it includes cementing and stimulation services. These services are provided to customers in major oil and natural gas producing areas of Canada.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

The Oilfield Services segment has five operating segments. These operating segments provide other oilfield services such as chemical services, casing and tubular services, process and pipeline services, completion tools and completion fluids services in the U.S. and in select markets internationally. These 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. We evaluate the performance of our segments based on operating income. Intersegment sales and transfers are not material.

Summarized financial information concerning our segments for each of the three years ended September 30, 2007, 2006, and 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, 2007, 2006 and 2005, we 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
  

Canada

Pressure

Pumping

   Oilfield
Services
Group
   Corporate     Total

2007

                

Revenue

   $ 2,562,747    $ 1,074,744    $ 386,547    $ 778,371    $ —       $ 4,802,409

Operating income (loss)

     881,631      152,734      32,493      163,539      (79,858 )     1,150,539

Total assets

     1,504,397      1,339,312      550,449      980,846      340,208       4,715,212

Capital expenditures

     289,278      210,684      83,643      82,796      85,712       752,113

Depreciation

     89,718      55,111      29,327      27,804      7,059       209,019

2006

                

Revenue

   $ 2,353,772    $ 884,670    $ 481,380    $ 648,042    $ —       $ 4,367,864

Operating income (loss)

     899,213      138,069      102,094      132,420      (100,060 )     1,171,736

Total assets

     1,294,946      1,022,265      471,362      707,015      366,700       3,862,288

Capital expenditures

     202,423      87,822      106,352      42,499      20,878       459,974

Depreciation

     65,569      49,119      24,025      22,730      5,320       166,763

2005

                

Revenue

   $ 1,683,202    $ 693,462    $ 348,448    $ 517,650    $ 424     $ 3,243,186

Operating income (loss)

     524,893      77,525      58,313      67,626      (91,298 )     637,059

Total assets

     1,049,019      855,054      351,034      594,950      559,585       3,409,642

Capital expenditures

     149,986      49,222      66,135      34,906      23,514       323,763

Depreciation

     51,990      43,835      16,892      20,206      3,938       136,861

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

Geographic Information

 

     Revenue   

Long-Lived

Assets

2007

     

United States

   $ 2,867,442    $ 2,069,306

Canada

     432,392      336,434

Other countries

     1,502,575      575,229
             

Consolidated total

   $ 4,802,409    $ 2,980,969
             

2006

     

United States

   $ 2,600,864    $ 1,732,411

Canada

     526,609      260,530

Other countries

     1,240,391      380,930
             

Consolidated total

   $ 4,367,864    $ 2,373,871
             

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
             

Revenue by Product Line

 

     2007    2006    2005

Cementing

   $ 1,231,643    $ 1,090,787    $ 822,447

Stimulation

     2,721,638      2,560,063      1,835,560

Other

     849,128      717,014      585,179
                    

Total revenue

   $ 4,802,409    $ 4,367,864    $ 3,243,186
                    

A reconciliation from the segment information to consolidated income before income taxes for each of the three years ended September 30, 2007 is set forth below (in thousands):

 

     2007     2006     2005  

Total operating income for reportable segments

   $ 1,150,539     $ 1,171,736     $ 637,059  

Interest expense

     (32,731 )     (14,558 )     (10,951 )

Interest income

     1,624       14,916       11,281  

Other (expense) income, net

     (6,584 )     (11 )     15,958  
                        

Income before income taxes

   $ 1,112,848     $ 1,172,083     $ 653,347  
                        

9. Employee Benefit Plans

Adoption of SFAS 158

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R) (“SFAS 158”), which requires companies to recognize the over funded or under funded status of a defined benefit postretirement

 

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Notes to the Consolidated Financial Statements—(Continued)

 

plan (other than a multiemployer plan) as an asset or liability in our statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. It also requires companies to measure the funded status of a plan as of the date of its year-end statement of financial position. We adopted all of the requirements of SFAS 158 for the fiscal year ended September 30, 2007. We had previously measured our defined benefit plan assets and obligations as of our fiscal year-end. Thus, this portion of SFAS 158 did not impact our financial statements. The impact of adopting the remaining requirements of SFAS 158 on our statement of financial position as of September 30, 2007 is shown below:

 

    

Before

Application

of SFAS 158

  

U.S.

Pensions

   

Non-U.S.

Pensions

   

Other

Postretirement

Benefits

    After
Application
of SFAS 158

Other current assets

   $ 63,414    $ (16,040 )   (2,612 )   —       $ 44,762

Current deferred income taxes

     14,037      5,957     —       —         19,994

Deferred income taxes

     27,676      —       2,795     —         30,471

Total assets

     4,725,112      (10,083 )   183     —         4,715,212

Deferred income taxes

     94,282      —       (90 )   1,293       95,485

Accrued postretirement benefits

     60,984      —         (3,480 )     57,504

Other long-term liabilities

     140,487      —       7,390     —         147,877

Accumulated other comprehensive income

     66,657      (10,083 )   (7,117 )   2,187       51,644

Total stockholders’ equity

     2,866,411      (10,083 )   (7,117 )   2,187       2,851,398

Total liabilities and stockholders’ equity

     4,725,112      (10,083 )   183     —         4,715,212

Defined Benefit Pension Plans

We have defined benefit pension plans covering certain employees in the U.S., the U.K., Norway and Canada. During fiscal 2004, the plans were frozen to new entrants in the U.K. and Canada.

The defined benefit pension plan in the U.S. was frozen effective December 31, 1995, at which time all earned benefits were vested. In September 2006, we entered into an agreement to settle our obligation with respect to the U.S. defined benefit plan. Plan assets of approximately $72 million, plus our contribution of $1.5 million, were used to purchase an insurance contract that is being used to fund the benefits and settle the plan. The proposed settlement requires approval from the Pension Benefit Guaranty Corporation and the Internal Revenue Service to relieve us of primary responsibility for the pension benefit obligation. Once regulatory approval is obtained, which is expected in fiscal 2008, we will expense approximately $23.3 million in connection with the settlement. This consists of $7 million of prepaid pension cost and $16 million of loss currently recognized in other comprehensive income. By relieving us of our obligation, the expense that would have otherwise been recognized over the remaining plan life will be accelerated to the period in which approval is received.

 

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BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

Obligations and Funded Status

 

     U.S.     Non-U.S.  
      2007     2006     2007     2006  

Change in benefit obligation

        

Benefit obligation, beginning of year

   $ 65,090     $ 64,490     $ 190,113     $ 152,646  

Service cost

     —         —         5,646       5,212  

Interest cost

     3,905       3,582       10,682       8,768  

Actuarial (gain)/loss

     —         689       (4,991 )     15,659  

Benefits paid from plan assets

     (3,584 )     (3,671 )     (4,986 )     (2,991 )

Contributions by plan participants

     —         —         2,143       2,085  

Curtailments

     —         —         (618 )     (83 )

Foreign currency exchange rate change

     —         —         20,684       8,817  
                                

Defined benefit plan obligation, end of year

   $ 65,411     $ 65,090     $ 218,673     $ 190,113  

Change in plan assets

        

Fair value of plan assets, beginning of year

   $ 72,196     $ 69,082     $ 129,127     $ 107,219  

Actual return on plan assets

     3,905       5,320       8,295       9,249  

Contributions by employer

     —         1,465       15,397       7,463  

Contributions by plan participants

     —         —         2,143       2,085  

Benefits paid from plan assets

     (3,584 )     (3,671 )     (4,986 )     (2,991 )

Settlements

     —         —         (81 )     —    

Foreign currency exchange rate change

     —         —         14,992       6,102  
                                

Fair value of plan assets, end of year

   $ 72,517     $ 72,196     $ 164,887     $ 129,127  

Over (under) funded status

   $ 7,106     $ 7,106     $ (53,786 )   $ (60,986 )

Unrecognized net actuarial loss

     N/A       16,040       N/A       56,369  

Unrecognized prior service cost

     N/A       —         N/A       —    

Unrecognized transitional loss

     N/A       —         N/A       2,723  
                                

Prepaid (accrued) net amount recognized

   $ 7,106     $ 23,146     $ (53,786 )   $ (1,894 )
                                

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

 

     U.S.    Non-U.S.  
     2007    2006    2007     2006  

Current asset

   $ 7,106    $ 23,146    $ —       $ 3,409  

Current liability

     —        —        (639 )     —    

Non-current liability

     —        —        (53,147 )     (52,200 )

Accumulated other comprehensive income

     N/A      N/A      N/A       46,897  
                              

Net amount recognized

   $ 7,106    $ 23,146    $ (53,786 )   $ (1,894 )
                              

The amounts recognized in accumulated other comprehensive income consist of the following as of September 30, 2007:

 

     U.S.    Non-U.S.

Net loss (gain)

   $ 16,040    $ 54,056

Net transition obligation

     —        264
             

Total

   $ 16,040    $ 54,320
             

 

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Table of Contents

BJ SERVICES COMPANY

Notes to the Consolidated Financial Statements—(Continued)

 

The estimated amortization of amounts reflected in accumulated other comprehensive income into the net periodic benefit cost is expected to be $10.0 million (net of tax) in fiscal 2008 for the U.S. plan, and is not expected to be material for the plans outside the U.S.

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 $268.1 million and $239.8 million at September 30, 2007 and 2006, respectively.

 

     U.S.    Non-U.S.
     2007    2006    2007    2006

Projected benefit obligation

   $ 65,411    $ 65,090    $ 218,673    $ 190,113

Accumulated benefit obligation

     65,411      65,090      202,714      177,128

Plan assets at fair value

     72,517      72,196      164,887      129,127

Components of Net Periodic Benefit Cost

 

     U.S.     Non-U.S.  
     2007     2006     2005     2007     2006     2005  

Service cost for benefits earned

   $ —       $ —       $ —       $ 5,646     $ 5,212     $ 4,823  

Interest on projected benefit obligation

     3,905       3,582       3,826       10,682       8,768       7,609  

Expected return on plan assets

     (3,905 )     (5,732 )     (5,343 )     (9,696 )     (8,114 )     (6,898 )

Recognized actuarial loss

     —         587       587       3,097       2,170       2,209  

Net amortization

     —         —         —         (39 )     18       74  
                                                

Net pension cost (benefit)

   $ —       $ (1,563 )   $ (930 )   $ 9,690     $ 8,054     $ 7,817  
                                                

Assumptions

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

 

     U.S.     Non-U.S.  
     2007    2006     2005     2007     2006     2005  

Weighted-average discount rate

   N/A    6.0 % &nb