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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to .
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Commission file number 1-10570
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BJ SERVICES COMPANY
(Exact name of registrant as specified in its charter)
Delaware 63-0084140
(State or other
jurisdiction of
incorporation or (I.R.S. Employer
organization) Identification No.)
5500 Northwest Central
Drive, Houston, Texas 77092
(Address of principal
executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 462-4239
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Securities Registered Pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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Common Stock $.10 par
value New York Stock Exchange
Preferred Share Purchase
Rights New York Stock Exchange
7% Series B Notes due 2006 New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [_].
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K ((S)229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K [_].
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). YES [X] NO [_].
At December 2, 2002, the registrant had outstanding 157,661,463 shares of
Common Stock, $.10 par value per share. The aggregate market value of the
Common Stock on March 31, 2002 (based on the closing prices in the daily
composite list for transactions on the New York Stock Exchange) held by
nonaffiliates of the registrant was approximately $5.4 billion.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of Registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held January 22, 2003 are incorporated by reference into
Part II and Part III.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Business.................................................................. 3
Item 2. Properties................................................................ 15
Item 3. Legal Proceedings......................................................... 16
Item 4. Submission of Matters to a Vote of Security Holders....................... 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..... 18
Item 6. Selected Financial Data................................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.............................................................. 21
Item 7A. Quantitative and Qualitative Disclosures about Market Risk................ 31
Item 8. Financial Statements and Supplementary Data............................... 31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.............................................................. 59
PART III
Item 10. Directors and Executive Officers of the Company........................... 59
Item 11. Executive Compensation.................................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and Management............ 59
Item 13. Certain Relationships and Related Transactions............................ 59
Item 14. Controls and Procedures................................................... 59
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 60
2
PART I
ITEM 1. Business
General
BJ Services Company (the "Company"), whose operations trace back to the
Byron Jackson Company (which was founded in 1872), was organized in 1990 under
the corporate laws of the state of Delaware. The Company is a leading provider
of pressure pumping and other oilfield services serving the petroleum industry
worldwide. The Company's pressure pumping services consist of cementing and
stimulation services used in the completion of new oil and natural gas wells
and in remedial work on existing wells, both onshore and offshore. Other
oilfield services include completion tools, completion fluids and 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 specialty chemical services.
In April 1995, the Company completed the acquisition of The Western Company
of North America ("Western" and the "Western Acquisition"), which provided the
Company with a greater critical mass with which to better compete in domestic
and international markets and the realization of significant consolidation
benefits. The Western Acquisition increased the Company's then existing total
revenue base by approximately 75% and more than doubled the Company's domestic
revenue base at that time. In addition, in excess of $40 million in annual
overhead and redundant operating costs were eliminated by combining the two
companies.
In June 1996, the Company completed the acquisition of Nowsco Well Service
Ltd. ("Nowsco" and the "Nowsco Acquisition"). Nowsco's operations were
conducted primarily in Canada, the United States, Europe, Southeast Asia and
Argentina and included pressure pumping and commissioning and inspection
services. The Nowsco Acquisition added approximately 40% to the Company's then
existing revenue base.
On May 31, 2002, the Company completed the acquisition of OSCA, Inc.
("OSCA"), a completion services (pressure pumping), completion tools and
completion fluids company based in Lafayette, Louisiana, with operations
primarily in the U.S. Gulf of Mexico, Brazil and Venezuela.
During the year ended September 30, 2002, the Company generated
approximately 86% of its revenue from pressure pumping services and 14% from
other oilfield services. Over the same period, the Company generated
approximately 52% of its revenue from U.S. operations and 48% from
international operations. For geographic and segment revenue details for each
of the three years ended September 30, 2002, see Note 8 of the Notes to
Consolidated Financial Statements.
Pressure Pumping Services
Cementing Services
The Company's cementing services, which accounted for approximately 29% of
total revenue during 2002, consist of blending high-grade cement and water with
various solid and liquid additives to create a slurry that is pumped into a
well between the casing and the wellbore. The additives and the properties of
the slurry are designed to achieve the proper cement set up time, compressive
strength and fluid loss control, and vary depending upon the well depth,
downhole temperatures and pressures, and formation characteristics.
The Company provides central, regional and district laboratory testing
services to evaluate slurry properties, which vary with cement supplier and
local water sources. Job design recommendations are developed by the Company's
field engineers to achieve desired compressive strength and bonding
characteristics.
There are a number of specific applications for cementing services used in
oilfield operations. The principal application is the cementing between the
casing pipe and the wellbore during the drilling and completion phase of a well
("primary cementing"). Primary cementing is performed to (i) isolate fluids
behind the casing between
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productive formations and other formations that would damage the productivity
of hydrocarbon producing zones or damage the quality of freshwater aquifers,
(ii) seal the casing from corrosive formation fluids, and (iii) provide
structural support for the casing string. Cementing services are also utilized
when recompleting wells from one producing zone to another and when plugging
and abandoning wells.
Stimulation Services
The Company's stimulation services, which accounted for approximately 55% of
total revenue during 2002, consist of fracturing, acidizing, sand control,
nitrogen, coiled tubing and downhole tool services. These services are designed
to improve the flow of oil and natural gas from producing formations and are
summarized as follows:
Fracturing. Fracturing services are performed to enhance the production of
oil and natural gas from formations having such permeability that the natural
flow is restricted. The fracturing process consists of pumping a fluid gel into
a cased well at sufficient pressure to "fracture" the formation. Sand, bauxite
or synthetic proppant that is suspended in the gel is pumped into the fracture
to prop it open. The size of a fracturing job is generally expressed in terms
of pounds of proppant, which can exceed 200,000 lbs. In some cases, fracturing
is performed by an acid solution pumped under pressure without a proppant or
with small amounts of proppant. The main pieces of equipment used in the
fracturing process are a blender, which blends the proppant and chemicals into
the fracturing fluid, multiple pumping units capable of pumping significant
volumes at high pressures, and a monitoring van loaded with real time
monitoring equipment and computers used to control the fracturing process. The
Company's fracturing units are capable of pumping slurries at pressures of up
to 17,800 pounds per square inch. In 1998, the Company embarked on a program to
replace its aging fleet with new, more efficient and higher horsepower pressure
pumping equipment. The Company has made significant progress with this program,
which is now approximately 50% complete. During 2000, the Company introduced
and successfully field tested the Gorilla(TM) pumping unit, a 3000 horsepower
frac unit that provides the highest horsepower pump available in the service
industry.
An important element of fracturing services is the design of the fracturing
treatment, which includes determining the proper fracturing fluid, proppants
and injection program to maximize results. The Company's field engineering
staff provide technical evaluation and job design recommendations as an
integral element of its fracturing service for the customer. Technological
developments in the industry over the past several years have focused on
proppant concentration control (i.e., proppant density), liquid gel concentrate
capabilities, computer design and monitoring of jobs and cleanup properties for
fracturing fluids. The Company introduced equipment to respond to these
technological advances. In 1998, the Company introduced a low polymer
fracturing fluid (Vistar(TM)) designed to provide greater fracture length with
minimal polymer residue. Vistar(TM) was commercialized in 1999 and is now used
in approximately 20% of the Company's U.S. fracturing treatments.
Acidizing. Acidizing enhances the flow rate of oil and natural gas from
wells with reduced flow caused by formation damage from drilling or completion
fluids, or the buildup over time of materials that block the formation.
Acidizing entails pumping large volumes of specially formulated acids into
reservoirs to dissolve barriers and enlarge crevices in the formation, thereby
eliminating obstacles to the flow of oil and natural gas. The Company maintains
a fleet of mobile acid transport and pumping units to provide acidizing
services for the onshore market, and maintains acid storage and pumping
equipment on most of its offshore stimulation vessels.
Sand Control. Sand control services involve pumping gravel to fill the
cavity created around a wellbore during drilling. The gravel provides a filter
for the exclusion of formation sand from the producing pathway. Oil and natural
gas are then free to move through the gravel into the wellbore. These services
are utilized primarily in unconsolidated reservoirs, mostly in the Gulf of
Mexico, the North Sea, Venezuela, Brazil, Trinidad, West Africa, Indonesia and
India. Completion tools, as described elsewhere herein, are often utilized in
conjunction with sand control services.
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Nitrogen. There are a number of uses for nitrogen, an inert gas, in
pressure pumping operations. Used alone, it is effective in displacing fluids
in various oilfield applications, including underbalanced drilling. However,
nitrogen services are used principally in applications supporting the Company's
coiled tubing and fracturing services.
Coiled Tubing. Coiled tubing services involve injecting coiled tubing into
wells to perform various well-servicing operations. The application of coiled
tubing has increased in recent years due to improvements in coiled tubing
technology. Coiled tubing is a flexible steel pipe with a diameter of less than
five inches manufactured in continuous lengths of thousands of feet and wound
or coiled along a large reel on a truck or skid-mounted unit. Due to the small
diameter of coiled tubing, it can be inserted through existing production
tubing and used to perform workovers without using a larger, more costly
workover rig. The other principal advantages of employing coiled tubing in a
workover include (i) not having to "shut-in" the well during such operations,
thereby allowing production to continue and reducing the risk of formation
damage to the well, (ii) the ability to reel continuous coiled tubing in and
out of a well significantly faster than conventional pipe, which must be
jointed and unjointed, (iii) the ability to direct fluids into a wellbore with
more precision, allowing for localized stimulation treatments and providing a
source of energy to power a downhole motor or manipulate downhole tools and
(iv) enhanced access to remote or offshore fields due to the smaller size and
mobility of a coiled tubing unit.
Service Tools. The Company provides service tools and technical personnel
for well servicing applications in select markets throughout the world. Service
tools, which are used to perform a wide range of downhole operations to
maintain or improve a well, generally are rented by customers from the Company.
While marketed separately, service tools are usually provided during the course
of providing other pressure pumping services.
The Company participates in the offshore stimulation market through the use
of skid-mounted pumping units and operation of several stimulation vessels
including one in the North Sea, four in the Gulf of Mexico and five in South
America.
The Company believes that, as production continues to decline in key
producing fields of the U.S. and certain international regions, the demand for
fracturing and other stimulation services is likely to increase. Consequently,
the Company has been increasing its pressure pumping capabilities in certain
international markets over the past several years.
Other Oilfield Services
The Company's other oilfield services accounted for approximately 14% of the
Company's total revenue in 2002. The other oilfield services segment consists
of specialty chemicals, tubular services, process and pipeline services and,
with the acquisition of OSCA on May 31, 2002, completion tools and completion
fluids services in the U.S. and internationally.
Tubular Services. Tubular services comprise installing (or "running")
casing and production tubing into a wellbore. Casing is run to protect the
structural integrity of the wellbore and to seal various zones in the well.
These services are primarily provided during the drilling and completion phases
of a well. Production tubing is run inside the casing. Oil and natural gas are
produced through the tubing. These services are provided during the completion
and workover phases.
Process and Pipeline Services. Process and pipeline services involve
inspecting and testing the integrity of pipe connections in offshore drilling
and production platforms and onshore and offshore pipelines and industrial
plants, and are provided during the commissioning, decommissioning,
installation or construction stages of these infrastructures, as well as during
routine maintenance checks. Historically, hydrocarbon storage and production
facilities have been tested for leaks using either water under pressure or a
"live" system whereby oil, gas or water was introduced at operating pressure.
At remote locations such as offshore facilities, the volume of fresh water
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required to test a facility made its use impractical and the use of flammable
or toxic fluids created a risk of explosion or other health hazards. Commission
leak testing, or CLT, uses a nitrogen and helium gas mixture in conjunction
with certain specialized equipment to detect very small leaks in joints,
instruments and valves that form the components of such facilities. Although
the process is safer and more practical than traditional leak detection
methods, it may be more expensive. Accordingly its use is restricted to those
instances where environmental and safety concerns are particularly acute.
Pipeline testing and commissioning services include filling, pressure
testing, de-watering, purging and vacuum drying of pipelines. Other pipeline
services include grouting and insulating pipeline bundles. Recent technical
innovations include the development of pipeline gels, both hydrocarbon and
aqueous, for pipeline cleaning and transport as well as plugs used for
isolation purposes. The Company has also developed high friction pig trains and
freezing techniques for the isolation of sections of pipelines.
In conducting its pipeline inspection business, the Company uses
"intelligent pigs." Intelligent pigs are pipeline monitoring vehicles which,
together with interpretational software, offer to pipeline operators,
constructors and regulators measurement of pipeline geometry, determination of
pipeline location and orientation and examination of the pipeline's internal
condition. In addition, the customer can develop a structural analysis using
the measured pipeline geometry information. The operator's planning is improved
through the utilization of the data to determine the pipeline's status,
estimate current and future reliability and provide recommendations on remedial
or maintenance requirements which consider the severity of the problem
identified. Analysis work using intelligent pigs can be routinely performed
with maintenance monitoring programs implemented as a method for increasing
safety for people, property and the environment.
Specialty Chemical Services. Specialty chemical services are provided to
customers in the upstream and downstream oil and natural gas businesses through
the BJ Unichem division. These services involve the design of treatments and
the sale of products to reduce the negative effects of corrosion, scale,
paraffin, bacteria, and other contaminants in the production and processing of
oil and natural gas. BJ Unichem's products are used by customers engaged in
crude oil production, natural gas processing, raw and finished oil and natural
gas product transportation, refining, fuel additizing and petrochemical
manufacturing. BJ Unichem's services address two principal priorities: (1) the
protection of the customer's capital investment in metal goods, such as
downhole casing and tubing, pipelines and process vessels, and (2) the
treatment of fluids to allow them to meet the specifications of the particular
operation, such as production transferred to a pipeline, water discharged
overboard from a platform, or fuel sold at a marketing terminal.
Completion Tools. The Company designs, builds and installs downhole
completion tools that deploy gravel to control the migration of reservoir sand
into the well and direct the flow of oil and natural gas into the production
tubing.
The Company's completion tools are sold as complete systems, which are
customized based on each well's particular mechanical and reservoir
characteristics, such as downhole pressure, wellbore size and formation type.
Many wells produce from more than one reservoir simultaneously. Depending on
the customer's preference, the Company has the ability to install tools that
can either isolate one producing zone from another or integrate the production
from multiple zones. Once the tool systems are designed and customized, each is
inspected for quality assurance before it is delivered to the well location.
The Company's field specialists, working with the rig crews, deploy completion
tools in the well during the completion process.
To further enhance reservoir optimization, the Company has also developed
the tools necessary to provide the operator with "intelligent completion"
capabilities. This includes the ability to selectively control flow from
multiple reservoirs in the same wellbore from a remote activation site on
surface. In addition, through joint agreements with operators, the Company may
also provide the equipment necessary to monitor downhole parameters such as
temperature, pressure and reservoir flow to allow optimization of well
productivity.
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In addition to tools that are designed to control sand migration, the
Company also provides completion tools that are generally used in conventional
completions in reservoirs that do not require sand control. These tools include
production packers and other tools that are delivered through distribution
networks located in key domestic markets and select international markets.
Completion Fluids. The Company sells and recycles clear completion fluids
and performs related fluid maintenance activities, such as filtration and
reclamation. Completion fluids are used to control well pressure and facilitate
other completion activities, while minimizing reservoir damage. The Company
provides standardized completion fluids as well as a broad line of specially
formulated and customized fluids for high demand wells.
Completion fluids are clear brines of metallic salts, such as sodium,
potassium and calcium chloride; sodium, calcium and zinc bromide; and sodium
and potassium formate. All are available either as pure salt solutions or as
combinations of these solutions for increased flexibility and greater
cost-effectiveness. These fluids are solids-free, and therefore will not
physically plug oil and natural gas reservoirs. In contrast, drilling mud, the
fluid typically used during drilling and for some well completions contains
solids to achieve densities greater than water. These solids plug the
reservoir, causing reservoir damage and restricting the flow of oil and natural
gas into the well. When completion fluids are placed into a well, they
typically become contaminated with solids that are left in the well after
drilling mud is displaced. To remove these contaminants, the Company deploys
filtering equipment and technicians that work in conjunction with the Company's
on-site fluid engineers to maintain the solids-free condition of the completion
fluids throughout the project. The Company provides an entire range of
completion fluids, as well as all support services needed to properly apply
completion fluids in the field, including filtration, on-site engineering,
additives and rental equipment.
Operations
Pressure pumping services are provided both on land and offshore on a
24-hour, on-call basis through regional and district facilities in
approximately 200 locations worldwide. Services are provided utilizing complex
truck or skid-mounted equipment designed and constructed for the particular
pressure pumping service furnished. After equipment is moved to a well location
it is configured with appropriate connections to perform the services required.
The mobility of this equipment permits the Company to provide pressure pumping
services to wellsites in virtually all geographic areas. Management believes
that the Company's pressure pumping equipment is adequate to service both
current and projected levels of market activity in the near term.
The Company maintains a fleet of mobile cement pumping equipment for onshore
operations. Offshore operations are performed with skid-mounted cement pumping
units primarily using the Company's Recirculating Averaging Mixer ("RAM"). Most
cementing units are equipped with computerized systems that allow for real-time
monitoring and control of the cementing processes.
Principal materials utilized in pressure pumping include cement, fracturing
proppants, acid, guar polymers and other bulk chemical additives. Generally
these items are available from several suppliers, and the Company uses more
than one supplier for each item. The Company also produces certain of its
specialized pressure pumping products through company-owned blending facilities
in Germany, Singapore, Canada, the U.S. and Brazil. Sufficient material
inventories are generally maintained to allow the Company to provide on-call
services to its customers to whom the materials are sold in the course of
providing pressure pumping services. Repair parts and maintenance items for
pressure pumping equipment are carried in inventory at levels that the Company
believes will allow continued operations without significant downtime caused by
parts shortages. The Company has experienced only intermittent tightness in
supply or extended lead times in obtaining necessary supplies of these
materials or replacing equipment parts and does not anticipate any chronic
shortage of any of these items in the foreseeable future.
The Company believes that coiled tubing and other materials utilized in
performing coiled tubing services are and will continue to be widely available
from a number of manufacturers. Although there are only three principal
manufacturers of the reels around which the coiled tubing is wrapped, the
Company has not
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experienced any difficulty in obtaining coiled tubing reels in the past and
anticipates no such difficulty in the future.
Engineering and Support Services
The Company maintains three primary research and development centers - one
in Tomball, Texas (near Houston), one in Houston, Texas and the other in
Calgary, Alberta. The Company's research and development organization is
divided into six distinct areas: Product Development, Software Applications,
Instrumentation Engineering, Mechanical Engineering, Coiled Tubing Engineering
and Completion Tools Engineering.
Product Development. The product development laboratory specializes in
developing products with enhanced performance characteristics in the
fracturing, acidizing, sand control and cementing operations (i.e., "frac
fluids" and "cement slurries"). As fluids must perform under a wide range of
downhole pressures, temperatures and other conditions, this process is a
critical element in developing products to meet customer needs.
Software Applications. The Company's software applications group develops
and supports a wide range of proprietary software utilized in the monitoring of
both cement and stimulation job parameters. This software, combined with the
Company's internally developed monitoring hardware, allows for real-time job
control as well as post-job analysis.
Instrumentation Engineering. The pressure pumping industry utilizes an
array of monitoring and control instrumentation as an integral element of
providing cementing and stimulation services. The Company's monitoring and
control instrumentation, developed by its instrumentation engineering group,
complements its products and equipment and provides customers with desired
real-time monitoring of critical applications.
Mechanical Engineering. Though similarities exist between the major
competitors in the general design of their pumping equipment, the actual
engine/transmission configurations as well as the mixing and blending systems
differ significantly. Additionally, different approaches to the integrated
control systems result in equipment designs which are usually distinct in
performance characteristics for each competitor. The Company's mechanical
engineering group is responsible for the design and manufacturing of virtually
all of the Company's primary pumping and blending equipment. However, some
primary pumping equipment and certain peripheral support equipment which is
generic to the industry is purchased externally. The Company's mechanical
engineering group provides new product design as well as support to the
rebuilding and field maintenance functions.
Coiled Tubing Engineering. The coiled tubing engineering group is located
in Calgary, Alberta. This group provides most of the support and research and
development activities for the Company's coiled tubing services. Development
work for drilling applications (DUCT) involves using coiled tubing directional
drilling technology for completions and directional underbalanced drilling. The
Company is also actively involved in the ongoing development of downhole tools
that may be run on coiled tubing, including rotary jetting equipment and
through-tubing inflatable packer systems.
Completion Tools Engineering. The completions tools research facility
specializes in the designing, manufacturing and testing of completion tools.
Since the Company's tools are often installed miles below the earth's surface,
it is critical that potential design flaws be diagnosed and prevented prior to
installation. Measurements of different raw materials, operating conditions and
design specifications are used in determining optimal tool configuration.
Manufacturing
In addition to the engineering facility, the Company's research and
technology center near Houston also houses its main equipment and
instrumentation manufacturing facility. This operation currently occupies
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approximately 353,000 square feet and includes complete fabrication, pump
manufacturing, assembly, warehousing, laboratory, training and engineering
capabilities. The Company produces certain components required for the assembly
of downhole completion tools at a manufacturing facility in Mansfield, Texas.
The Company also has smaller manufacturing capabilities in several
international locations. The Company employs outside vendors for manufacturing
of its coiled tubing units, engine and transmission rebuilding, and certain
fabrication work, but is not dependent on any one source.
Competition
Pressure Pumping Services. There are two primary companies with which the
Company competes in pressure pumping services, Halliburton Energy Services, a
division of Halliburton Company, and Schlumberger Ltd. These companies have
operations in most areas of the U.S. in which the Company participates and in
most international regions. It is estimated that, exclusive of "captive"
service companies, these two competitors, along with the Company, provide over
90% of pressure pumping services to the industry. Several smaller companies
compete with the Company in certain areas of the U.S. and in certain
international locations. The principal methods of competition which apply to
the Company's business are its prices, service record and reputation in the
industry. While Halliburton Energy Services and Schlumberger are larger in
terms of overall pressure pumping revenues, the Company has the largest market
share position in certain areas.
Other Oilfield Services. The Company believes that it is one of the largest
suppliers of tubular services in the U.K. North Sea and has expanded such
services into other international markets in the past several years. The
largest provider of tubular services is Weatherford International, Inc. In the
U.K., tubular services are typically provided under long-term contracts which
limit the opportunities to compete for business until the end of the contract
term. In continental Europe, shorter-term contracts are typically available for
bid by the provider of tubular services. The Company believes it is the largest
provider of commissioning and leak detection services and one of the largest
providers of pipeline inspection services. In specialty chemical services,
there are several competitors significantly larger than the BJ Unichem
division. The Company's principal competitors in completion fluids are Baroid
Corporation, a subsidiary of Halliburton Company; M-I LLC, a joint venture of
Smith International, Inc. and Schlumberger Limited; and Tetra Technologies,
Inc. The Company's principal competitors in completion tools are Halliburton
Energy Services, a division of Halliburton Company; Schlumberger Limited, and
Baker Hughes Incorporated.
Markets and Customers
Demand for the Company's services and products depends primarily upon the
number of oil and natural gas wells being drilled, the depth and drilling
conditions of such wells, the number of well completions and the level of
workover activity worldwide.
The Company's principal customers consist of major and independent oil and
natural gas producing companies. During 2002, the Company provided oilfield
services to several thousand customers, none of which accounted for more than
5% of consolidated revenues. While the loss of certain of the Company's largest
customers could have a material adverse effect on Company revenues and
operating results in the near term, management believes the Company would be
able to obtain other customers for its services in the event of a loss of any
of its largest customers.
United States. The United States represents the largest single oilfield
services market in the world. The Company provides its pressure pumping
services to its U.S. customers through a network of over 50 locations
throughout the U.S., a majority of which offer both cementing and stimulation
services. Demand for the Company's pressure pumping services in the U.S. is
primarily driven by oil and natural gas drilling activity, which tends to be
extremely volatile depending on the current and anticipated prices of oil and
natural gas. Due to aging oilfields and lower-cost sources of oil
internationally, drilling activity in the U.S. has declined more than 75% from
its peak in 1981. Record low drilling activity levels were experienced in 1986
and 1992 and again in
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1999. Despite a recovery in the latter half of fiscal 1999, the U.S. average
fiscal 1999 rig count of 601 active rigs represented the lowest in recorded
history. The recovery in U.S. drilling, however, continued throughout fiscal
2000 and 2001 due to exceptionally strong oil and natural gas prices, yet
drilling activity retreated in fiscal 2002. For the 12 months ended September
30, 2002, the active U.S. rig count averaged 870 rigs, a 26% decrease from
fiscal 2001. Much of the decrease occurred in the number of rigs drilling for
natural gas, which decreased 23% from the previous fiscal year. Crude oil and
natural gas prices have stabilized over the past several months and U.S.
drilling activity has leveled out. The Company's management believes that such
activity will remain flat for the next six months and increase moderately in
the second half of fiscal 2003. During fiscal 2002, the Company expanded its
deepwater offshore stimulation capabilities in the Gulf of Mexico through the
acquisition of OSCA, which added two stimulation vessels, and the commissioning
of the "Blue Ray" stimulation vessel in November 2001.
International. The Company operates in over 40 countries in the major
international oil and natural gas producing areas of Latin America, Europe,
Africa, Russia, Asia, Canada and the Middle East. The Company generally
provides services to its international customers through wholly-owned foreign
subsidiaries. Additionally, the Company holds certain controlling and minority
interests in several joint venture companies, through which it conducts a
portion of its international operations. The Company's Canadian operations now
represent its largest international operation with approximately 11% of
consolidated revenue in fiscal 2002.
Drilling activity outside North America has historically been less volatile
than the U.S. market. Due to the significant investment and complexity in
international projects, management believes drilling decisions relating to such
projects tend to be evaluated and monitored with a longer-term perspective with
regard to oil and natural gas pricing. Additionally, the international market
is dominated by major oil companies and national oil companies which tend to
have different objectives and more operating stability than the typical
independent producer in North America. International activities have been
increasingly important to the Company's results of operations since 1992, when
the Company implemented a strategy to expand its international presence. During
fiscal 2001, the Company completed expansion projects in Saudi Arabia,
Kazakhstan and West Africa. In 2002, the Company expanded in Russia through the
purchase of additional workover rigs and enhanced its market position in the
Brazilian offshore market with the addition of the "Blue Shark" stimulation
vessel. In addition, the Company expanded its service offering in Brazil
through the acquisition of OSCA, and by acquiring the assets and business of a
leading provider of coiled tubing services.
The Company now operates in most of the major oil and natural gas producing
regions of the world. International operations are subject to special risks
that can materially affect the sales and profits of the Company, including
currency exchange rate fluctuations, the impact of inflation, governmental
expropriation, exchange controls, political instability and other risks. The
Company mitigates the risk of currency exchange rate fluctuations by invoicing
the majority of its international services in U.S. dollars.
Employees
At September 30, 2002, the Company had a total of 11,130 employees.
Approximately 62% of the Company's employees were employed outside the United
States. At September 30, 2002, the Company had a sufficient number of trained
employees to meet customer requirements. However, in times of rapidly expanding
activity temporary labor shortages may occur.
Governmental and Environmental Regulation
The Company's business is affected both directly and indirectly by
governmental regulations relating to the oil and natural gas industry in
general, as well as environmental and safety regulations which have specific
application to the Company's business.
The Company, through the routine course of providing its services, handles
and stores bulk quantities of hazardous materials. In addition, leak detection
services involve the inspection and testing of facilities for leaks
10
of hazardous or volatile substances. If leaks or spills of hazardous materials
handled, transported or stored by the Company occur, the Company may be
responsible under applicable environmental laws for costs of remediating damage
to the surface, sub-surface or aquifers incurred in connection with such
occurrence. Accordingly, the Company has implemented and continues to implement
various procedures for the handling and disposal of hazardous materials. Such
procedures are designed to minimize the occurrence of spills or leaks of these
materials.
The Company has implemented and continues to implement various procedures to
further assure its compliance with environmental regulations. Such procedures
generally pertain to the operation of underground storage tanks, disposal of
empty chemical drums, improvement to acid and wastewater handling facilities
and cleaning of certain areas at the Company's facilities. The estimated future
cost for such procedures is $5.0 million, which will be incurred over a period
of several years, and for which the Company has provided appropriate reserves.
In addition, the Company maintains insurance for certain environmental
liabilities which the Company believes is reasonable based on its knowledge of
the industry.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," imposes liability without regard to fault or the
legality of the original conduct, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
Certain third-party owned disposal facilities used by the Company or its
predecessors have been investigated under state and federal Superfund statutes,
and the Company is currently named as a potentially responsible party for
cleanup at three such sites. Although the Company's level of involvement varies
at each site, in general, the Company is one of numerous parties named and will
be obligated to pay an allocated share of the cleanup costs. While it is not
feasible to predict the outcome of these matters with certainty, management is
of the opinion that their ultimate resolution should not have a material
adverse effect on the Company's operations or financial position.
Research and Development; Patents
Research and development activities for pressure pumping services are
directed primarily toward improvement of existing products and services and the
design of new products and processes to meet specific customer needs. The
Company currently holds numerous patents of varying remaining durations
relating to products and equipment used in its pumping services business. While
such patents, in the aggregate, are important to maintaining the Company's
competitive position, no single patent is considered to be of a critical or
essential nature.
To remain competitive, the Company devotes significant resources to
developing technological improvements to its pumping services products. Many of
these improvements have centered on improving products in fracturing systems
and, more recently, in deepwater cementing applications.
In 1991, the Company introduced a borate-based fracturing fluid, Spectra
Frac(R) G, which is being widely used in the U.S. stimulation market and the
North Sea. In 1993, this product was complemented with two additional
fracturing fluids, Spartan Frac(R) and Medallion Frac(R), which have expanded
the Company's services line offering to cover a broader range of economic and
downhole design variables. During 1994, the Company commercialized a
proprietary enzyme process used in conjunction with the three fracturing
fluids. These "enzyme breakers" significantly enhance the production of oil and
natural gas in a wide range of wells. During 1998, the Company introduced a low
polymer fracturing fluid (Vistar(TM)) designed to provide greater fracture
length with minimal polymer residue. This product has been successfully
utilized in a wide variety of applications since 1998. During 1999 and 2000,
the Company successfully field tested in the U.S. a low and mid stress range
deformable particle (FlexSand(TM)) designed to prevent proppant flowback and
extend the life of the fracturing treatment. During 2001 and 2002, the Company
commercialized the FlexSand(TM) additive globally and successfully field tested
a high stress range version of the deformable particle.
11
To address the trend towards more deepwater completions, the Company has
developed DeepSet(TM), a cementing system designed to handle low sea floor
temperatures, and further commercialized automated foam cementing equipment
designed to address shallow water flows typically found in deepwater
environments.
During 2000 and 2001, the Company successfully field tested and
commercialized the TST-3(TM) service tool packer. This packer provides the
latest in service tool technology and operational efficiency. During 2001 and
2002, the Company successfully field tested and commercialized a composite
drillable bridge plug, the Python(TM). The Python(TM) plug performs at
temperatures to 375(degrees)F and differential pressures greater than 10,000
pounds per square inch.
The testing and development of new products is an integral part of the
Company's pipeline inspection and coiled tubing businesses. Developments
include a MFL corrosion inspection tool; ROTO-JET(R), a tool for use in
wellbore scale removal; the SandVac(TM)/Well Vac(TM) treatment tool (a licensed
tool incorporating a hydraulic jet pump to effectively remove sand and other
particles hindering production from the wellbore); the Tornado(TM) treatment
tool (a patent pending tool employing switchable rearward facing jets that can
be used to remove sand from deviated wellbores at much higher efficiencies than
previously obtainable); and various downhole tools and other technologies used
in directional drilling applications using coiled tubing. During 2001 and 2002,
the Company globally commercialized the LEGS(TM) (lateral entry guidance
system) tool for use with coiled tubing re-entry into vertical and horizontal
wells containing lateral wellbores. The LEGS(TM) tool provides the technology
to locate and successfully enter laterals for workover operations in existing
wells. Additionally, the Company operates under various license arrangements,
generally ranging from 10 to 20 years in duration, relating to certain products
or techniques. None of these license arrangements is material.
During 2002, the Company actively marketed Liquid Stone(TM), a patented
storable cement slurry, as a primary cementing method in both land and offshore
operations. Liquid Stone(TM) technology produces a high quality,
fit-for-purpose cement slurry that can be stored in a liquid state for a period
of days or weeks prior to placement in the well.
During 2002, the Company actively marketed its patented AquaCon(TM) Relative
Permeability Modifier (RPM) technology for water control and production
enhancement applications. AquaCon(TM) is a unique and versatile RPM system that
is effective in both matrix and fracturing treatment applications, and in both
sandstone and carbonate formations.
The Company intends to continue to devote significant resources to its
research and development efforts. For information regarding the amounts of
research and development expenses for each of the three fiscal years ended
September 30, 2002, see Note 11 of the Notes to Consolidated Financial
Statements.
Risk Factors
This document and our other filings with the Securities and Exchange
Commission and our other materials released to the public contain
"forward-looking statements," as defined in the Private Securities Litigation
Reform Act of 1995. These forward-looking statements discuss the Company's
prospects, expected revenues, expenses and profits, strategies for its
operations and other subjects, including conditions in the oilfield service and
oil and gas industries and in the United States and international economy in
general.
Our forward-looking statements are based on assumptions that we believe to
be reasonable but that may not prove to be accurate. All of the Company's
forward-looking information is, therefore, subject to risks and uncertainties
that could cause actual results to differ materially from the results expected.
Although it is not possible to identify all factors, these risks and
uncertainties include the risk factors discussed below.
Business Risks. The Company's results of operations could be adversely
affected if its business assumptions do not prove to be accurate or if adverse
changes occur in the Company's business environment, including the following
areas:
. general global economic and business conditions,
12
. potential declines or increased volatility in oil and natural gas prices
that would adversely affect our customers and the energy industry,
. potential reductions in spending on exploration and development drilling
by customers in the oil and natural gas industry that would reduce demand
for our products and services,
. the actions of the Organization of the Petroleum Exporting Countries
(OPEC),
. capital and equity market conditions,
. business opportunities that may be available to and pursued by the
Company,
. our ability to integrate technological advances and compete on the basis
of advanced technology,
. competition and consolidation in our businesses and
. potential higher prices for products used by the Company in its
operations.
Risks of Economic Downturn. Because of the recent economic downturn in the
United States and many foreign economies as well as hostilities following
September 11, 2001, there may be decreased demand and lower prices for oil and
natural gas and therefore 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.
Risks from Operating Hazards. The Company's operations are subject to
hazards present in the oil and natural gas industry, such as fire, explosion,
blowouts and oil spills. These incidents as well as accidents or problems in
normal operations can cause personal injury or death and damage to property or
the environment. The customer's operations can also be interrupted. From time
to time, customers seek to recover from the Company for damage to their
equipment or property that occurred while the Company was performing work.
Damage to the customer's property could be extensive if a major problem
occurred. For example, operating hazards could arise:
. in the pressure pumping business, during work performed on oil and gas
wells,
. in the specialty chemical business, as a result of use of the Company's
products in refineries, and
. in the process and pipeline business, as a result of work performed by
the Company at petrochemical plants as well as on pipelines.
Risks from Unexpected Litigation. The Company has insurance coverage
against operating hazards that it believes is customary in the industry.
However, the insurance has large deductibles and exclusions from coverage. The
Company's insurance premiums can be increased or decreased based on the claims
made by the Company under its insurance policies. The insurance does not cover
damages from breach of contract by the Company or based on alleged fraud or
deceptive trade practices. Whenever possible, the Company obtains agreements
from customers that limit the Company's liability. Insurance and customer
agreements do not provide complete protection against losses and risks, and the
Company's results of operations could be adversely affected by unexpected
claims not covered by insurance.
Risks from International Operations. The Company's international operations
are subject to special risks that can materially affect the Company's sales and
profits. These risks include:
. 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,
. fluctuations and changes in currency exchange rates,
13
. the impact of inflation and
. governmental action such as expropriation of assets, general legislative
and regulatory environment, exchange controls, changes in global trade
policies such as trade restrictions and embargoes imposed by the United
States and other countries, and changes in international business,
political and economic conditions.
Other Risks. Other risk factors that could cause actual results to be
different from the results we expect include:
. weather conditions that affect operating conditions in the oil and
natural gas industry,
. changes in environmental laws and other governmental regulations and
. changes in the conduct of business, logistics, supply, transportation and
security measures in effect since September 11, 2001.
Many of these risks are beyond the control of the Company. In addition,
future trends for pricing, margins, revenues 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 publicly update any of our forward-looking statements.
Available Information
The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13 (a) or 15 (d) of the Exchange Act are made available
free of charge on the Company's internet website at http://www.bjservices.com
as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the Securities and Exchange Commission.
Executive Officers of the Registrant
The current executive officers of the Company and their positions and ages
are as follows:
Name Age Position with the Company Since
---- --- ------------------------- -----
J. W. Stewart...... 58 Chairman of the Board, President and Chief Executive Officer 1990
David Dunlap....... 41 Vice President and President - International Division 1995
Mark Hoel.......... 44 Vice President--Technology and Logistics 2002
Brian McCole....... 43 Controller 2002
Margaret B. Shannon 53 Vice President--General Counsel 1994
Jeffrey E. Smith... 40 Treasurer 2002
T. M. Whichard..... 44 Vice President--Finance and Chief Financial Officer 2002
Kenneth A. Williams 52 Vice President and President - U.S. Division 1991
Stephen A. Wright.. 55 Director of Human Resources 1987
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. Dunlap joined the Company in 1984 as a District Engineer and was named
Vice President--International Operations in December 1995. He has previously
served as Vice President--Sales for the Coastal Division of North America and
U.S. Sales and Marketing Manager.
14
Mr. Hoel joined the Company in 1992 as an Account Manager and was named
Region Sales Manager in 1993. He previously served as Vice President of Sales
for the U.S. Western Division, prior to being named Vice
President--Manufacturing and Logistics in 2002.
Mr. McCole originally joined the Company as Director of Internal Audit in
1991. He also served as Controller of the Asia Pacific Region and Controller of
the Unichem division. He left the Company in 1998 and returned in 2001 to serve
as Director of Internal Audit until becoming Controller in 2002.
Ms. Shannon joined the Company in 1994 as Vice President--General Counsel
from the law firm of Andrews & Kurth L.L.P., where she had been a partner since
1984.
Mr. Smith joined the Company in 1990 as Financial Reporting Manager. He also
served as Director, Financial Planning. In 1997 he was promoted to Director,
Business Development, a position he held until being named Treasurer in 2002.
Prior to joining BJ Services, he held various positions with Baker Hughes
Incorporated.
Mr. Whichard joined the Company as Tax and Treasury Manager in 1989 from
Weatherford International and was named Treasurer in 1992 and Vice President in
1998. Prior to being named Vice President, Finance and Chief Financial Officer
in 2002, he served in various positions including Treasurer, Tax Director and
Assistant Treasurer.
Mr. Williams joined the Company in 1973 and has since held various positions
in the U.S. operations. Prior to being named Vice President--North American
Operations in 1991, he served as Region Manager--Western U.S. and Canada.
Mr. Wright joined the Company as Manager of Compensation and Benefits in
1985 from Global Marine Inc., an offshore drilling company, and assumed his
current position with the Company in 1987.
ITEM 2. Properties
The Company's properties consist primarily of pressure pumping and blending
units and related support equipment such as bulk storage and transport units.
Although a portion of the Company's U.S. pressure pumping and blending fleet is
being utilized through a servicing agreement with an outside party, the
majority of its worldwide fleet is owned and unencumbered. The Company's
tractor fleet, most of which is owned, is used to transport the pumping and
blending units. The majority of the Company's light duty truck fleet, both in
the U.S. and international operations, is also owned.
The Company both owns and leases regional and district facilities from which
pressure pumping services and other oilfield services are provided to
land-based and offshore customers. The Company's principal executive offices in
Houston, Texas are leased. The technology and research centers located near
Houston, Texas and Calgary, Alberta are owned by the Company, as are blending
facilities located in Germany, Singapore and Canada. The Company owns and
operates a calcium chloride manufacturing plant in Geismar, Louisiana. This
facility neutralizes hydrochloric acid with calcium carbonate, generating
industrial strength, technical grade calcium chloride. The Company leases a
37,000 square foot facility in Mansfield, Texas that houses the manufacturing
of components for the assembly of its downhole completion tools. The Company
operates several stimulation vessels, including one which is owned in the North
Sea and five in South America and four in the Gulf of Mexico on which the hulls
are leased. The Company believes that its facilities are adequate for its
current operations. For additional information with respect to the Company's
lease commitments, see Note 10 of the Notes to Consolidated Financial
Statements.
15
ITEM 3. Legal Proceedings
The Company, through performance of its service operations, is sometimes
named as a defendant in litigation, usually relating to claims for bodily
injuries or property damage (including claims for well or reservoir damage).
The Company maintains insurance coverage against such claims to the extent
deemed prudent by management. The Company believes that there are no existing
claims that are likely to have a materially adverse effect on the Company for
which it has not already provided.
Through acquisition the Company assumed responsibility for certain claims
and proceedings made against Western, Nowsco and OSCA in connection with their
businesses. Some, but not all, of such claims and proceedings will continue to
be covered under insurance policies of the Company's predecessors that were in
place at the time of the acquisitions. Although the outcome of the claims and
proceedings against the Company (including Western, Nowsco and OSCA) cannot be
predicted with certainty, management believes that there are no existing claims
or proceedings that are likely to have a materially adverse effect on the
Company. See Government and Environmental Regulation under Item 1, Business
above.
Chevron Phillips Litigation
On July 10, 2002, Chevron Phillips Chemical Company ("Chevron Phillips")
filed a lawsuit against BJ Services Company ("BJ") for patent infringement in
the United States District Court for the Southern District of Texas (Corpus
Christi). The lawsuit relates to a patent issued in 1992 to the Phillips
Petroleum Company ("Phillips"). This patent (the '477 patent) relates to a
method for using enzymes to decompose drilling mud. Although BJ has its own
patents for remediating damage resulting from drill-in fluids (as opposed to
drilling muds) in oil and gas formations (products and services for which are
offered under the "Mudzyme" mark), we approached Phillips for a license of the
'477 patent. BJ was advised that Phillips had licensed this patent on an
exclusive basis to Geo-Microbial Technologies, Inc. ("GMT"), a company co-owned
by a former Phillips employee who is one of the inventors on the '477 patent,
and that BJ should deal with GMT in obtaining a sublicense. BJ entered into a
five (5) year sublicense agreement with GMT in 1997.
Early in 2000, Phillips advised BJ that Phillips had reportedly terminated
the license agreement between Phillips and GMT for non-payment of royalties and
that BJ's sublicense had also terminated. Even though BJ believes that its
sublicense with GMT has not been properly terminated and BJ's Mudzyme
treatments may not be covered by the '477 patent, in 2000, BJ stopped offering
its enzyme product for use on drilling mud and drill-in fluids in the U.S.
Nevertheless, Chevron Phillips is claiming that the use of enzymes in
fracturing fluids and other applications in the oil and gas industry falls
under the '477 patent. Further, even though their patent is valid only in the
United States, Chevron Phillips is requesting that the court award it damages
for BJ's use of enzymes in foreign countries on the theory that oil produced
from wells treated with enzymes is being imported into the United States.
BJ disputes Chevron Phillips' interpretation of the '477 patent and its
theory of damages, and will vigorously defend itself against the allegations.
Further, it is BJ's position that Phillips should be bound by the terms of the
sublicense agreement between BJ and GMT. As with any lawsuit, the outcome of
this case is uncertain. Given the scope of the claims made by Chevron Phillips,
an adverse ruling against BJ could result in a substantial verdict. However, BJ
management does not presently believe it is likely that the results of this
litigation will have a material adverse impact on BJ's financial position or
the results of our operations.
Halliburton - Python Litigation
On June 27, 2002, Halliburton Energy Services, Inc. filed suit against BJ
and Weatherford International, Inc. for patent infringement in connection with
drillable bridge plug tools. These tools are used to isolate portions of a well
for stimulation work, after which the plugs are milled out using coiled tubing
or a workover rig. Halliburton claims that tools offered by BJ (under the trade
name "Python") and Weatherford infringed two of its patents for
16
a tool constructed of composite material. The lawsuit has been filed in the
United States District Court for the Northern District of Texas (Dallas).
Halliburton has requested that the District court issue a temporary restraining
order against both Weatherford and BJ to prevent either company from selling
competing tools. In addition, Halliburton has requested expedited discovery and
a hearing on a preliminary injunction. BJ and Weatherford have filed responses
to the various Halliburton requests and the matter is currently under
consideration by the Court.
We believe that the current design of the Python plug offered by BJ does not
infringe any of the valid claims in the two Halliburton patents. We also
believe the Halliburton patents are invalid based upon prior art demonstrated
in products offered well before Halliburton filed for its patents. BJ has sold
approximately 150 Python tools since the inception of this product in the
summer of 2001. We believe that we have no liability for infringement of the
Halliburton patents. Moreover, even if the patent is found to be enforceable
and we are found to have infringed it, BJ management does not believe it is
likely that the results of this litigation will have a material adverse impact
on BJ's financial position or the results of our operations.
Halliburton - Vistar Litigation
On March 17, 2000, BJ Services Company filed a lawsuit against Halliburton
Energy Services in the United Sates District Court for the Southern District of
Texas (Houston). In the lawsuit BJ alleged that a well fracturing fluid system
used by Halliburton infringes a patent issued to BJ in January 2000 for a
method of well fracturing referred to by BJ as "Vistar(TM)". This case was
tried in March and April of 2002. The jury reached a verdict in favor of BJ on
April 12, 2002. The jury determined that BJ's patent was valid and that
Halliburton's competing fluid system, Phoenix, infringed the BJ patent. The
District Court has entered a judgment for $101.1 million and a permanent
injunction preventing Halliburton from using its Phoenix system. The case is
now on appeal to the Court of Appeals for the Federal Circuit in Washington,
D.C.
Newfield Litigation
On April 4, 2002, a jury rendered a verdict adverse to OSCA in connection
with litigation pending in the United States District Court for the Southern
District of Texas (Houston). The lawsuit arose out of a blowout that occurred
in 1999 on an offshore well owned by Newfield Exploration. The jury determined
that OSCA's negligence caused or contributed to the blowout and that it was
responsible for 86% of the damages suffered by Newfield. The total damage
amount awarded to Newfield was $15.5 million. OSCA's share of the judgment
would be $13.3 million. The Court has delayed entry of the final judgment in
this case pending the completion of the related insurance coverage litigation
filed by OSCA against certain of its insurers and its former insurance broker.
The Court elected to conduct the trial of the insurance coverage issues based
upon the briefs of the parties. The briefs have been submitted and the parties
are awaiting a ruling from the Court. In the interim, the related litigation
filed by OSCA against its former insurance brokers for errors and omissions in
connection with the policies at issue in this case has been stayed. Great Lakes
Chemical Corporation, which formerly owned the majority of the outstanding
shares of OSCA, has agreed to indemnify BJ for 75% of any uninsured liability
in excess of $3 million arising from the Newfield litigation. The Company
believes it is adequately reserved for this contingency.
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, 2002.
17
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Common Stock of the Company began trading on The New York Stock Exchange
in July 1990 under the symbol "BJS". At December 2, 2002 there were
approximately 3,175 holders of record of the Company's Common Stock.
The following table sets forth for the periods indicated the high and low
sales prices per share for the Company's Common Stock reported on the NYSE
composite tape. All amounts prior to the 2 for 1 stock split effective May 31,
2001 have been retroactively restated to reflect the increased number of common
shares outstanding resulting from the stock split.
Common Stock
Price Range
-------------
High Low
------ ------
Fiscal 2001
1st Quarter............................ $36.50 $24.00
2nd Quarter............................ 43.10 30.50
3rd Quarter............................ 41.95 27.75
4th Quarter............................ 28.82 14.55
Fiscal 2002
1st Quarter............................ 34.05 16.85
2nd Quarter............................ 35.90 25.30
3rd Quarter............................ 39.49 31.75
4th Quarter............................ 35.19 23.00
Fiscal 2003
1st Quarter (through December 2, 2002). 34.79 24.31
Since its initial public offering in 1990, BJ Services has not paid any cash
dividends to its stockholders. The Company expects that, for the foreseeable
future, any earnings will be retained for the development of the Company's
business or used for the share repurchase program discussed below and,
accordingly, no cash dividends are expected to be declared on the Common Stock.
At September 30, 2002, there were 173,755,324 shares of Common Stock issued and
156,795,191 shares outstanding. On March 22, 2001, the Company's Board of
Directors approved a 2 for 1 stock split, which was effected on May 31, 2001 in
the form of a stock dividend, for holders of record on May 17, 2001. On
December 19, 1997, the Company's Board of Directors authorized a stock
repurchase program of up to $150 million (subsequently increased to $300
million in May 1998, to $450 million in September 2000, to $600 million in July
2001 and again to $750 million in October 2001). Repurchases are made at the
discretion of the Company's management and the program will remain in effect
until terminated by the Company's Board of Directors. Under this program, the
Company has repurchased 12,792,800 shares at a cost of $219.4 million through
fiscal 2000, 7,014,200 shares at a cost of $177.5 million during fiscal 2001,
and 4,376,000 shares at a cost of $102.1 million in fiscal 2002.
On April 24, 2002 the Company sold convertible senior notes with a face
value at maturity of $449.0 million (gross proceeds of $355.1 million). The
Company also granted an over-allotment option of 15%, which was exercised in
full for an additional face value at maturity of $67.4 million (gross proceeds
of $53.3 million). The notes are unsecured senior obligations that rank equally
in right of payment with all of the Company's existing and future senior
unsecured indebtedness. The Company used the aggregate net proceeds of $400.1
million to fund a substantial portion of its acquisition of OSCA and for
general corporate purposes.
The notes will mature in 20 years and cannot be called by the Company for
three years after issuance. The redemption price must be paid in cash if the
notes are called. Holders of the notes can require the Company to repurchase
the notes on the third, fifth, tenth and fifteenth anniversaries of the
issuance. The Company has the
18
option to pay the repurchase price in cash or stock. The issue price of the
notes was $790.76 for each $1,000 in face value, which represents a yield to
maturity of 1.625%. Of this 1.625% yield to maturity, 0.50% per year on the
issue price will be paid in cash for the life of the security.
The notes are convertible into BJ Services common stock at an initial rate
of 14.9616 shares for each $1,000 face amount note. This rate results in an
initial conversion price of $52.85 per share (based on purchaser's original
issue discount) and represents a premium of 45% over the April 18, 2002 closing
sale price of the Company's common stock on the New York Stock Exchange of
$36.45 per share. The Company has the option to settle notes that are
surrendered for conversion using cash. Generally, except upon the occurrence of
specified events, including a credit rating downgrade to below investment
grade, holders of the notes are not entitled to exercise their conversion
rights until the Company's stock price is greater than a specified percentage
(beginning at 120% and declining to 110% at the maturity of the notes) of the
accreted conversion price per share. At September 30, 2002, the accreted
conversion price per share would have been $53.11.
The Company has a Stockholder Rights Plan (the "Rights Plan") designed to
deter coercive takeover tactics and to prevent an acquirer from gaining control
of the Company without offering a fair price to all of the Company's
stockholders. The Rights Plan was amended September 26, 2002, to extend the
expiration date of the Rights to September 26, 2012 and increase the purchase
price of the Rights. Under this plan, as amended, each outstanding share of
Common Stock includes one-quarter of a preferred share purchase right ("Right")
that becomes exercisable under certain circumstances, including when beneficial
ownership of Common Stock by any person, or group, equals or exceeds 15% of the
Company's outstanding Common Stock. Each Right entitles the registered holder
to purchase from the Company one one-thousandth of a share of Series A Junior
Participating Preferred Stock at a price of $520, subject to adjustment under
certain circumstances. As a result of stock splits effected in the form of
stock dividends in 1998 and 2001, one Right is associated with four outstanding
shares of Common Stock. The purchase price for the one-fourth of a Right
associated with one share of Common Stock is effectively $130. Upon the
occurrence of certain events specified in the Rights Plan, each holder of a
Right (other than an Acquiring Person) will have the right, upon exercise of
such Right, to receive that number of shares of Common Stock of the Company (or
the surviving corporation) that, at the time of such transaction, would have a
market price of two times the purchase price of the Right. No shares of Series
A Junior Participating Preferred Stock have been issued by the Company at
September 30, 2002.
Information concerning securities authorized for issuance under equity
compensation plans is set forth in the section entitled "Executive
Compensation" in the Proxy Statement of the Company for the Annual Meeting of
Stockholders to be held January 22, 2003, which section is incorporated herein
by reference. Under the Company's Employee Stock Purchase Plan for the year
ended September 30, 2002, 661,215 shares of Common Stock were issued at a price
of $15.12 per share.
19
ITEM 6. Selected Financial Data
The following table sets forth certain selected historical financial data of
the Company. The selected operating and financial position data as of and for
each of the five years in the period ended September 30, 2002 have been derived
from the audited consolidated financial statements of the Company, some of
which appear elsewhere in this Annual Report. This information should be read
in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Consolidated Financial Statements
and Notes thereto which are included elsewhere herein.
As of and For the Year Ended September 30,
----------------------------------------------------------
2002(1)(3) 2001 2000 1999(2) 1998
---------- ---------- ---------- ---------- ----------
(in thousands, except per share amounts)
Operating Data:
Revenue................................. $1,865,796 $2,233,520 $1,555,389 $1,131,334 $1,527,468
Operating expenses, excluding unusual
charges and goodwill amortization..... 1,602,737 1,683,561 1,346,667 1,092,879 1,289,295
Goodwill amortization................... 13,739 13,497 13,525 13,824
Unusual charges(4)...................... 39,695 26,586
Operating income (loss)................. 263,059 536,220 195,225 (14,765) 197,763
Interest expense........................ (8,979) (13,282) (19,968) (31,365) (25,685)
Other income (expense), net............. (3,394) 3,676 (1,550) 613 (772)
Income tax expense (benefit)............ 86,199 179,922 57,307 (15,221) 54,654
Net income (loss)....................... 166,495 349,259 117,976 (29,688) 117,400
Earnings (loss) per share(5):
Basic............................... 1.06 2.13 74 (.21) 79
Diluted............................. 1.04 2.09 70 (.21) 72
Depreciation and amortization........... 104,915 104,969 102,018 99,800 91,497
Capital expenditures(6)................. 179,007 183,414 80,518 110,566 167,961
Financial Position Data (at end of period):
Property, net........................... $ 798,956 $ 676,445 $ 585,394 $ 659,717 $ 602,028
Total assets............................ 2,442,370 1,985,367 1,785,233 1,824,764 1,743,701
Long-term debt, excluding current
maturities............................... 489,062 79,393 141,981 422,764 241,869
Stockholders' equity.................... 1,418,628 1,370,081 1,169,771 877,089 900,064
- --------
(1) Includes the effect of the acquisition of OSCA, Inc. in May 2002, which was
accounted for as a purchase in accordance with generally accepted
accounting principles. For further details, see Note 3 of the Notes to
Consolidated Financial Statements.
(2) Includes the effect of the acquisition of Fracmaster in June 1999, which
was accounted for as a purchase in accordance with generally accepted
accounting principles.
(3) The Company ceased amortizing goodwill on October 1, 2001 in accordance
with its adoption of Financial Accounting Standards Board Statement No.
142, "Goodwill and Other Intangible Assets". For further details, see Note
2 of the Notes to Consolidated Financial Statements.
(4) Unusual charges represent nonrecurring costs associated with the downturn
in oilfield drilling activity in 1999 and 1998.
(5) Earnings per share amounts have been restated for all periods presented to
reflect the increased number of common shares outstanding resulting from
the 2 for 1 stock splits effective January 30, 1998 and May 31, 2001.
(6) Excluding acquisitions of businesses.
20
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
The Company's worldwide operations are primarily driven by the number of oil
and natural gas wells being drilled, the depth and drilling conditions of such
wells, the number of well completions and the level of workover activity.
Drilling activity, in turn, is largely dependent on the price of crude oil and
natural gas. This situation often leads to volatility in the Company's revenues
and profitability, especially in the United States and Canada, where the
Company historically has generated in excess of 50% of its revenues.
Due to "aging" oilfields and lower-cost sources of oil internationally,
drilling activity in the United States has declined more than 75% from its peak
in 1981. Record low drilling activity levels were experienced in 1986, 1992 and
again in early 1999. Despite a recovery in the latter half of fiscal 1999, the
U.S. average fiscal 1999 rig count of 601 active rigs represented the lowest in
history. A recovery in U.S. drilling occurred in fiscal 2000 and 2001 due to
exceptionally strong oil and natural gas prices, yet drilling activity
retreated in fiscal 2002. For the 12 months ended September 30, 2002, the
active U.S. rig count averaged 870 rigs, a 26% decrease from fiscal 2001 and a
3% increase over fiscal 2000. Much of the decrease occurred in the number of
rigs drilling for natural gas, which for fiscal 2002 decreased 23% from the
previous fiscal year. Crude oil and natural gas prices have stabilized over the
past several months and U.S. drilling activity has leveled out. The Company's
management believes that such activity will remain flat for the next six months
and increase moderately in the second half of fiscal 2003.
Drilling activity outside North America has historically been less volatile
than domestic drilling activity. International drilling activity also reached
record low levels during 1999 due to low oil prices during most of the year.
While Canadian drilling activity began to recover during the latter part of
fiscal 1999, activity in most of the other international regions did not begin
to significantly recover until the latter half of fiscal 2001. Active
international drilling rigs (excluding Canada) averaged 730 rigs during fiscal
2002, a decrease of 1% from fiscal 2001. Canadian drilling activity declined in
fiscal 2002 averaging 265 active drilling rigs, down 27% from the previous
fiscal year. The Company expects international drilling activity (including
Canada) in fiscal 2003 to be consistent with levels experienced in fiscal 2002.
Critical Accounting Policies
The Company has defined a critical accounting policy as one that is both
important to the portrayal of the Company's financial condition and results of
operations and requires the management of the Company to make difficult,
subjective or complex judgments. Estimates and assumptions about future events
and their effects cannot be perceived with certainty. The Company bases its
estimates on historical experience and on various other assumptions that are
believed to be reasonable under the circumstances, the results of which form
the basis for making judgments. These estimates may change as new events occur,
as more experience is acquired, as additional information is obtained and as
the Company's operating environment changes. The Company believes the following
are the most critical accounting policies used in the preparation of the
Company's consolidated financial statements and the significant judgments and
uncertainties affecting the application of these policies. For information
concerning the Company's other significant accounting policies, see Note 2 of
the Notes to Consolidated Financial Statements.
Accounts Receivable: 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 current credit
information. We continuously monitor collections and payments from our
customers and maintain a provision for estimated uncollectible accounts based
upon our historical experience and any specific customer collection issues that
we have identified. While such credit losses have historically been within our
expectations and the provisions established, we cannot give any assurances that
we will continue to experience the same credit loss rates that we have in the
past. The cyclical nature of our industry may affect our customers' operating
performance and cash flows, which could impact our ability to collect on these
obligations. In addition, many of
21
our customers are located in certain international areas that are inherently
subject to risks of economic, political and civil instabilities, which may
impact our ability to collect these accounts receivables.
Inventory: The Company records inventory at the lower of cost or market.
The Company regularly reviews inventory quantities on hand and records
provisions for excess or obsolete inventory based primarily on its estimated
forecast of product demand, market conditions, production requirements and
technological developments. Significant or unanticipated changes to the
Company's forecasts could require additional provisions for excess or obsolete
inventory.
Income Taxes: We provide for income taxes in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 109, Accounting for Income Taxes.
This standard takes into account the differences between financial statement
treatment and tax treatment of certain transactions. Deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. The effect of a change in tax rates is recognized as
income or expense in the period that includes the enactment date. This
calculation requires 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.
Valuation Allowance for Deferred Tax Assets: 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 or that future deductibility is not probable. The
ultimate realization of the deferred tax assets depends on the ability to
generate sufficient taxable income of the appropriate character in the future.
Impairment of Long-Lived Assets: Long-lived assets, which include property,
plant and equipment, goodwill and other intangibles, and other assets comprise
a significant amount of the Company's total assets. The Company makes judgments
and estimates in conjunction with the carrying value of these assets, including
amounts to be capitalized, depreciation and amortization methods and useful
lives. Additionally, the carrying values of these assets are periodically
reviewed for impairment or whenever events or changes in circumstances indicate
that the carrying amounts may not be recoverable. An impairment loss is
recorded in the period in which it is determined that the carrying amount is
not recoverable. This requires the Company to make long-term forecasts of its
future revenues and costs related to the assets subject to review. These
forecasts require assumptions about demand for the Company's products and
services, future market conditions and technological developments. Significant
and unanticipated changes to these assumptions could require a provision for
impairment in a future period.
Self Insurance Accruals: The Company is self-insured for certain losses
relating to workers' compensation, general liability, property damage and
employee medical benefits. As such, the Company makes judgements based on
historical experience and current events to estimate our liability for such
claims. Significant and unanticipated changes in future actual payouts could
result in additional increases or decreases to the recorded accruals. We have
purchased stop-loss coverage in order to limit, to the extent feasible, our
aggregate exposure to certain claims. There is no assurance that such coverage
will adequately protect the Company against liability from all potential
consequences.
Contingencies: Contingencies are accounted for in accordance with the
Financial Accounting Standards Board's SFAS No. 5, "Accounting for
Contingencies" ("SFAS No. 5"). SFAS No. 5 requires that we record an estimated
loss from a loss contingency when information available prior to the issuance
of our financial statements indicates that it is probable that an asset has
been impaired or a liability has been incurred at the date of the financial
statements and the amount of the loss can be reasonably estimated. Accounting
for contingencies such as environmental, legal, and income tax matters requires
us to use our 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 over or
understated.
22
Acquisition
On May 31, 2002, the Company completed the acquisition of OSCA, Inc.
("OSCA"), a completion services (pressure pumping), completion tools and
completion fluids company based in Lafayette, Louisiana, with operations
primarily in the U.S. Gulf of Mexico, Brazil and Venezuela for a total purchase
price of $470.6 million. See Note 3 of the Notes to the Consolidated Financial
Statements for additional information regarding this acquisition.
Results of Operations
The following table sets forth selected key operating statistics reflecting
industry rig count and the Company's financial results:
2002 2001 2000
-------- -------- --------
Rig Count: (1)
U.S..................................................... 870 1,172 842
International........................................... 995 1,100 952
Consolidated revenue (in millions):........................ $1,865.8 $2,233.5 $1,555.4
Revenue by business segment (in millions):.................
U.S./Mexico Pressure Pumping............................ $ 898.7 $1,219.4 $ 732.5
International Pressure Pumping.......................... 712.6 794.7 629.2
Other Oilfield Services................................. 253.7 219.0 193.7
Percentage of gross profit to revenue (2).................. 23.1% 32.0% 22.2%
Percentage of research and engineering expense to revenue.. 2.0% 1.5% 1.7%
Percentage of marketing expense to revenue................. 3.4% 2.8% 3.4%
Percentage of general and administrative expense to revenue 3.6% 3.0% 3.6%
Consolidated operating income (in millions):............... $ 263.1 $ 536.2 $ 195.2
Operating income by business segment (in millions)(R) (3)..
U.S./Mexico Pressure Pumping............................ $ 189.1 $ 425.1 $ 136.7
International Pressure Pumping.......................... 72.1 126.9 67.3
Other Oilfield Services................................. 30.2 34.4 23.0
- --------
(1) Industry estimate of drilling activity as measured by average active
drilling rigs.
(2) Gross profit represents revenue less cost of sales and services.
(3) Operating income by segment excludes goodwill amortization. See Note 8 of
the Notes to the Consolidated Financial Statements.
Revenue: Due to declines in U.S. and Canadian drilling activity and
pricing, the Company's revenue for fiscal 2002 declined 16% to $1.87 billion
from record revenues recorded in fiscal 2001 of $2.23 billion. The fiscal 2001
revenues increased 44% over fiscal 2000 and reflected significant improvements
in the U.S. market, in both activity and pricing. Management expects the
Company's fiscal 2003 revenues to increase approximately 10% reflecting the
fiscal 2002 acquisition of OSCA and an otherwise flat market.
Operating Income: Operating income for fiscal 2002 was $263.1 million, a
decrease of $273.2 million from the previous fiscal year. The Company's gross
profit was $430.3 million in fiscal 2002, a decrease of 40% from fiscal 2001.
The gross profit decline was primarily due to activity and pricing declines in
the U.S. and Canadian markets. In addition there were increases in research and
engineering, marketing and general and administrative expenses of $3.4 million
primarily as a result of the acquisition of OSCA. These were offset by a $13.7
million decline in goodwill amortization as a result of the Company's adoption
of SFAS 142, as described in Note 2 of the Notes to the Consolidated Financial
Statements.
For the year ended September 30, 2001, operating income was $536.2 million,
an increase of $341.0 million over the previous fiscal year. The Company's
gross profit was $713.8 million in fiscal 2001, an increase of
23
106.8% over fiscal 2000. The margin improvement was primarily a result of
pricing improvement in the U.S., better equipment utilization and labor
efficiencies. Partially offsetting the improved margins were increases in
research and engineering, marketing and general and administrative expenses
totaling $27.5 million due to increased costs to support the higher revenue
level and higher employee incentive costs, which are based upon the Company's
earnings and stock price performance. Each of these operating expenses,
however, declined as a percentage of revenues.
Other: Interest expense in 2002 decreased by $4.3 million compared to the
previous year due to lower average debt levels throughout the year. Interest
expense in 2001 decreased by $6.7 million compared to 2000 due to repayment of
$82.7 million of debt with improved cash flow from operations. Interest income
in 2002 was $2.0 million compared with $2.6 million in fiscal 2001 and $1.6
million in fiscal 2000. This income is derived from overnight investing of
excess cash from operations.
Other expense, net was $3.4 million in 2002 compared with other income, net
of $3.7 million in fiscal 2001. Other expense in 2002 consists primarily of
minority interest expense of $4.9 million offset partially by a $1.5 million
gain resulting from an insurance recovery for Russian assets destroyed in a
fire. Included in other income in 2001 was a non-recurring $12.9 million gain
realized on the sale of a joint venture operation in Russia. Partially
offsetting this gain was minority interest expense for the year of $6.8 million
and a $1.7 million premium associated with the repurchase and retirement of $46
million of the Company's 7% notes maturing in 2006. Other expense, net in
fiscal 2000 consisted primarily of minority interest expense of $3.3 million,
which was partially offset by a settlement gain of $1.5 million recognized on
the conversion of a pension plan in Canada.
Income Taxes: The Company's effective tax rate has remained below the U.S.
statutory rate during each of the past three years primarily as a result of
profitability in international jurisdictions where the statutory tax rate is
less than the U.S. rate, the availability of certain non-recurring tax benefits
and the availability of tax benefits from the Company's reorganization pursuant
to its initial public offering in 1990. The effective tax rate was 34.1% in
2002, 34.0% in 2001 and 32.7% in 2000.
U.S./Mexico Pressure Pumping Segment
The Company's U.S./Mexico pressure pumping revenues declined $320.7 million,
or 26% in fiscal 2002 to $898.7 million from the previous year's record of
$1.22 billion. The decline was primarily due to decreased drilling and workover
activity which declined 26% and 14%, respectively, from the prior year and
lower prices in the U.S. as the market weakened. The fiscal 2001 revenues
represented a 66% increase over 2000 revenues. This increase occurred primarily
due to increased drilling and workover activity, which increased 39% and 18%,
respectively over the prior year, along with an average improvement in U.S.
pricing for the Company's products and services of approximately 20%. In
addition, revenue in the Company's Mexico operations increased by $16.9 million
in fiscal 2001 compared to 2000 as a result of a new contract. Management
believes that fiscal 2003 revenues generated by its U.S./Mexico pressure
pumping operations will increase only slightly as activity levels are not
expected to improve until the second half of fiscal 2003.
Operating income for the Company's U.S./Mexico pressure pumping operations
decreased $235.9 million, or 56% from the prior year to $189.1 million in
fiscal 2002. The decrease was due primarily to decreased revenues resulting
from the decline in drilling and workover activity and corresponding lower
prices for the Company's products and services as the market weakened. The
Company's average U.S. pricing declined approximately 7% from the previous
fiscal year. Also contributing to the decline was increased labor costs as a
percentage of revenue and higher depreciation resulting from the U.S. fleet
recapitalization initiative, a program which began in late 1998 to rebuild and
upgrade the Company's core fleet of fracturing pumping units in the U.S.
Operating income for the Company's U.S./Mexico pressure pumping operations was
$425.1 million in fiscal 2001, an increase of $288.4 million over fiscal 2000.
The improvement was due primarily to increased activity, improved pricing,
better equipment utilization, and labor efficiencies. Operating income for the
Company's U.S./Mexico pressure pumping operations was $136.7 million in fiscal
2000.
24
International Pressure Pumping Segment
Revenue for the Company's international pressure pumping operations was
$712.6 million in fiscal 2002, a decrease of $82.1 million, or 10% compared
with the previous fiscal year. The revenue decrease is largely attributable to
the Company's Canadian operations, with a 27% decrease in revenue corresponding
to a 27% drop in drilling activity from the previous year. The Company also had
a decrease in revenues in Latin America of 19% as compared to the prior year
due primarily to activity declines in Argentina and Venezuela as a result of
political uncertainties and economic declines. Revenue from operations in the
Eastern Hemisphere (which includes the Company's operations in Europe and
Africa, the Middle East, Asia Pacific, Russia and China) increased 5%
year-over-year led by increases in the Middle East. Increased activity levels
in India and Kazakstan are the main contributors to the Middle East growth. In
fiscal 2001, revenue for the Company's international pressure pumping
operations was $794.7 million, an increase of 26% compared with fiscal 2000.
This was the result of an increase in Canadian gas drilling, increased
stimulation activity in several international regions and contributions from
international geographic expansions. Revenue for the Company's international
pressure pumping operations was $629.2 million in fiscal 2000. Based on
expected drilling and activity levels, revenues for the Company's international
pressure pumping operations are expected to improve slightly in fiscal 2003
from 2002 levels.
Operating income for the Company's international pressure pumping operations
was $72.1 million for fiscal 2002, a decrease of $54.8 million, or 43% from the
prior year primarily due to reduced activity in Canada and political
uncertainties and economic declines in Argentina and Venezuela, combined with
approximately $4 million of combined costs from the devaluation of Argentina's
currency and severance costs incurred in connection with reductions in
personnel in Canada and Latin America during the second quarter of fiscal 2002.
The Eastern Hemisphere experienced a 4% decrease in operating income from
fiscal 2001 primarily due to decreased profitability in the Europe and Africa
region. As a result of the improved activity in fiscal 2001, operating income
for the Company's international pressure pumping operations was $126.8 million,
an increase of $59.5 million over the previous year. In addition to the
increased activity, operating margins as a percentage of revenues improved from
11% in fiscal 2000 to 16% in fiscal 2001 due mostly to startup costs in
selected international locations that negatively impacted operating margins in
fiscal 2000. Operating income for the Company's international pressure pumping
operations was $67.3 million in fiscal 2000.
Other Oilfield Services Segment
Revenue for the Company's other oilfield service lines, which consist of
specialty chemicals, tubular services, process and pipeline services,
completion tools and completion fluids, were $253.7 million in fiscal 2002, an
increase of $34.7 million, or 16% over the previous year. Approximately $32
million of the increase relates to the completion fluids and completion tools
service lines acquired with OSCA effective May 31, 2002. Other oilfield
services revenues (excluding completion fluids and completion tools) increased
3% in fiscal 2002 as compared to the prior year. Tubular service revenues
increased by 15% through activity improvements and expansion in West Africa and
the Middle East. The process and pipeline and specialty chemicals division
revenues were flat year-over-year.
Operating income for the Company's other oilfield service lines decreased
$4.2 million, or 12% from fiscal 2001 despite the year-over-year revenue
increase due to reduced profit margins in process and pipeline services
operations combined with $1.7 million of costs associated with the acquisition
of OSCA, consisting primarily of the disposal of completion tools deemed
obsolete as a result of the combination. Operating income for the Company's
other oilfield service lines increased $11.4 million above fiscal 2000 figures
to reach $34.4 million (15.7% of related revenue) for the year ended September
30, 2001. Operating income margins in the Company's tubular services and
process and pipeline services lines benefited most from the increased revenue
as they were better able to cover their relatively high fixed cost base.
Operating income for these service lines was $23.0 million (11.9% of related
revenue) in fiscal 2000.
25
Capital Resources and Liquidity
At September 30, 2002, cash and cash equivalents equaled $84.7 million
compared with $84.1 million and $6.5 million at the end of fiscal years 2001
and 2000, respectively.
Net cash provided from operating activities for fiscal 2002 totaled $343.9
million, a decrease of $173.7 million compared with 2001 primarily due to
reduced profitability, partially offset by the liquidation of working capital,
particularly accounts receivable. Net cash provided from operating activities
in fiscal 2001 increased $312.8 million from that of fiscal 2000 due primarily
to higher profitability and $130.0 million of cash benefit resulting from the
utilization of U.S. tax loss carryforwards. This was partially offset by
increases in working capital, particularly accounts receivable, as a result of
the revenue growth in North America.
In fiscal 2002, cash flows used in investing activities totaled $647.6
million, primarily attributable to amounts required to fund acquisitions as
well as the Company's capital expenditure needs. The 2002 capital spending of
$179.0 million was used primarily for replacement and enhancement of U.S.
fracturing equipment and expansion of stimulation and cementing services
internationally. Net cash used for investing activities in fiscal 2001 was
$188.7 million, compared to net cash provided by investing activities in 2000
of $43.7 million. Fiscal 2001 capital spending of $183.4 million was the
largest portion of the net cash used for investing activities. Capital
expenditures for fiscal 2001 increased $102.9 million from 2000 and were used
to replace and enhance U.S. fracturing equipment and expand stimulation
resources internationally.
Capital expenditures for fiscal 2003 are expected to be at a level
consistent with fiscal 2002 spending at approximately $180 million. The 2003
capital program is expected to consist primarily of spending for the
enhancement of the Company's existing pressure pumping equipment, investment in
the U.S. fracturing fleet recapitalization initiative and stimulation expansion
internationally. The actual amount of 2003 capital expenditures will be
primarily dependent on the availability of expansion opportunities and is
expected to be funded by cash flows from operating activities and available
credit facilities. Management believes cash flows from operating activities and
available lines of credit, if necessary, will be sufficient to fund projected
capital expenditures.
Cash flows required to fund investing activities in fiscal 2002 exceeded
cash flows from operations. The incremental cash requirements of the Company
were funded with $400.1 million in proceeds, net of transaction costs,
generated through the issuance of convertible senior notes on April 24, 2002.
Other financing activities in fiscal 2002 include the purchase of 4.4 million
shares of the Company's common stock at a cost of $102.1 million under a share
repurchase program initially approved by the Company's Board of Directors in
December 1997. The share repurchase program, as amended, authorizes purchases
up to $750 million, $251.0 million of which was available for future purchase
as of September 30, 2002. Cash flows used for financing activities for fiscal
2001 were $251.2 million, compared to cash flows of $245.9 million used for
financing activities in fiscal 2000. In connection with the June 2001
replacement of its existing credit facility, the Company prepaid $30.3 million
of borrowings that were outstanding under the term loan portion of the credit
facility. Also in June 2001, the Company repurchased and retired $46 million of
its 7% notes maturing in 2006 and recorded associated debt extinguishment costs
of $1.7 million (classified as other expense), consisting mainly of a $1.3
million early payment premium. In addition to the repayment of debt during
fiscal 2001, the Company purchased 7.0 million shares of its common stock at a
cost of $177.5 million. In September 2000, the Company also repurchased 800,000
shares of its common stock at a cost of $22.8 million. Other financing
activities in fiscal 2000 included a private placement of 8.1 million shares of
common stock in October 1999 that generated proceeds of $144.0 million, which
was used to pay outstanding debt. In connection with the private placement, the
Company also entered into privately negotiated option agreements pursuant to
which it repurchased an equivalent number of shares in April 2000 for a total
of $149.0 million. In April 2000, the Company utilized proceeds of $143.5
million from the exercise of outstanding warrants, combined with borrowings
under existing credit facilities, to fund the repurchase of these shares.
26
Management strives to maintain low cash balances while utilizing available
credit facilities to meet the Company's capital needs. Any excess cash
generated has historically been used to pay down outstanding borrowings or fund
the Company's share repurchase program. In June 2001, the Company replaced its
existing credit facility with a new $400 million committed line of credit
("Committed Credit Facility"). The Committed Credit Facility consists of a $200
million, 364-day commitment that renews annually at the option of the lenders
and a $200 million three-year commitment. The 364-day commitment that expired
in June 2002 was renewed for an additional 364 days. There were no outstanding
borrowings under the Committed Credit Facility at September 30, 2002.
In addition to the Committed Credit Facility, the Company had $129.0 million
in various unsecured, discretionary lines of credit at September 30, 2002,
which expire at various dates in 2003. There are no requirements for commitment
fees or compensating balances in connection with these lines of credit and
interest on borrowings is based on prevailing market rates. There was $3.5
million and $14.0 million in outstanding borrowings under these lines of credit
at September 30, 2002 and 2001, respectively.
On April 24, 2002 the Company sold convertible senior notes with a face
value at maturity of $516.4 million (gross proceeds of $408.4 million). The
notes are unsecured senior obligations that rank equally in right of payment
with all of the Company's existing and future senior unsecured indebtedness.
The Company used the aggregate net proceeds of $400.1 million to fund a
substantial portion of the purchase price of its acquisition of OSCA which
closed on May 31, 2002 and for general corporate purposes.
The notes will mature in 20 years and cannot be called by the Company for
three years after issuance. The redemption price must be paid in cash if the
notes are called. Holders of the notes can require the Company to repurchase
the notes on the third, fifth, tenth and fifteenth anniversaries of the
issuance. The Company has the option to pay the repurchase price in cash or
stock. The issue price of the notes was $790.76 for each $1,000 in face value,
which represents a yield to maturity of 1.625%. Of this 1.625% annual yield to
maturity, 0.50% per year on the issue price will be paid semi-annually in cash
for the life of the security.
The notes are convertible into BJ Services common stock at an initial rate
of 14.9616 shares for each $1,000 face amount note. This rate results in an
initial conversion price of $52.85 per share (based on the purchaser's original
issue discount) and represents a premium of 45% over the April 18, 2002 closing
sale price of the Company's common stock on the New York Stock Exchange of
$36.45 per share. The Company has the option to settle notes that are
surrendered for conversion using cash. Generally, except upon the occurrence of
specified events, including a credit rating downgrade to below investment
grade, holders of the notes are not entitled to exercise their conversion
rights until the Company's stock price is greater than a specified percentage
(beginning at 120% and declining to 110% at the maturity of the notes) of the
accreted conversion price per share. At September 30, 2002, the accreted
conversion price per share would have been $53.11.
In fiscal 2002, the Company entered into two long-term vessel charter
operating lease agreements. Annual commitments under these agreements for the
years ending September 30, 2003, 2004, 2005, 2006 and 2007 are $6.0 million,
$6.1 million, $6.3 million, $6.0 million and $3.6 million, respectively, and
$27.3 million in the aggregate thereafter.
In December 1999, the Company completed a transaction involving the transfer
of certain pumping service equipment assets and received $120.0 million that
was used to pay outstanding bank debt. The equipment is used to provide
services to customers for which the Company pays a service fee over a period of
at least six, but not more than 13 years. The transaction generated a deferred
gain, included in other long-term liabilities, of approximately $63 million,
which is being amortized over 13 years.
In 1997, the Company completed a transaction involving the transfer of
certain pumping service equipment assets and received $100.0 million that was
used to pay outstanding bank debt. The equipment is used to provide services to
the Company's customers for which the Company pays a service fee over a period
of at least eight,
27
but not more than 14 years. The transaction generated a deferred gain, included
in other long-term liabilities, of approximately $38 million, which is being
amortized over 12 years.
Due primarily to the April 2002 issuance of convertible senior notes, the
Company's total interest-bearing debt increased to 25.8% of its total
capitalization (total capitalization equals the sum of interest-bearing debt
and stockholders' equity) at September 30, 2002, compared to 6.4% at September
30, 2001. The Committed Credit Facility includes various customary covenants
and other provisions including the maintenance of certain profitability and
solvency ratios, none of which materially restrict the Company's activities.
Management believes that the Committed Credit Facility, combined with other
discretionary credit facilities and cash flows from operations, provides the
Company with sufficient capital resources and liquidity to manage its routine
operations, meet debt service obligations and fund projected capital
expenditures. If the discretionary lines of credit are not renewed, or if
borrowings under these lines of credit otherwise become unavailable, the
Company expects to refinance this debt by arranging additional committed bank
facilities or through other long-term borrowing alternatives.
The following table summarizes the Company's contractual cash obligations
and other commercial commitments as of September 30, 2002 (in thousands):
Payments Due by Period
------------------------------------------
Less than 4-5 After 5
Contractual Cash Obligations Total 1 Year 1-3 Years Years Years
- ---------------------------- --------- --------- --------- ------- --------
Long term debt.................................... $489,062 $ 78,839 $410,223
Capital lease obligations......................... 256 $ 256
Operating leases.................................. 129,036 30,121 56,424 $14,318 28,173
Obligations under equipment financing arrangements 187,432 21,852 70,300 47,614 47,666
-------- ------- -------- ------- --------
Total Contractual Cash Obligations................ $805,786 $52,229 $205,563 $61,932 $486,062
======== ======= ======== ======= ========
Amount of commitment expiration per period
Total ------------------------------------------
Amounts Less than 4-5 Over 5
Other Commercial Commitments Committed 1 Year 1-3 Years Years Years
- ---------------------------- --------- --------- --------- ------- --------
Standby Letters of Credit......................... $ 19,172 $19,087 $ 85
Guarantees........................................ 53,790 15,807 25,424 $ 8,177 $ 4,382
-------- ------- -------- ------- --------
Total Commercial Commitments...................... $ 72,962 $34,894 $ 25,509 $ 8,177 $ 4,382
======== ======= ======== ======= ========
Accounting Pronouncements
Effective October 1, 2001, the Company adopted Financial Accounting
Standards Board Statement No. 142, "Goodwill and Other Intangible Assets"
("SFAS 142"). SFAS 142 requires that goodwill no longer be amortized to
earnings but instead must be reviewed for possible impairment. The Company
ceased the amortization of goodwill beginning October 1, 2001. According to the
requirements of SFAS 142, the Company performed a transitional fair value based
impairment test on its goodwill and determined that fair value exceeded the
recorded amount at October 1, 2001, therefore no impairment loss has been
recorded. The Company's net goodwill balance at September 30, 2002 has been
assessed by management to be fully recoverable.
In August 2001, the Financial Accounting Standards Board "FASB" issued SFAS
No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143
requires the fair value of a liability for an asset retirement legal obligation
to be recognized in the period in which it is incurred. When the liability is
initially recorded, associated costs are capitalized by increasing the carrying
amount of the related long-lived asset. Over time, the liability is accreted to
its present value each period and the capitalized cost is depreciated over the
useful life of the related asset. SFAS 143 is effective for fiscal years
beginning after June 15, 2002. SFAS 143
28
requires entities to record the cumulative effect of a change in accounting
principle in the income statement in the period of adoption. The Company will
adopt SFAS 143 on October 1, 2002 and does not expect the adoption of this
standard to have a material impact on the Company's financial position or
results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 provides new guidance
on the recognition of impairment losses on long-lived assets to be held and
used or to be disposed and also broadens the definition of what constitutes a
discontinued operation and how the results of a discontinued operation are to
be measured and presented. SFAS 144 supercedes SFAS No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
and APB Opinion No. 30, while retaining many of the requirements of these two
statements. Under SFAS 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from ongoing operations and the reporting
entity will not have any significant continuing involvement in the discontinued
o