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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
COMMISSION FILE NO. 1-16337
OIL STATES INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0476605
(State or other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
THREE ALLEN CENTER, 333 CLAY STREET, SUITE 3460, HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(713) 652-0582
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
------------------- ------------------------------------
Common Stock, par value $.01 per share 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 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 Exchange Act Rule 12b-2). Yes [X] No [ ]
State the aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant:
Voting common stock (as of June 30, 2003)............ $ 316,768,393
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date:
As of February 27, 2004 Common Stock, par value $.01 per share 49,187,129 shares
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's Definitive Proxy Statement for the 2004
Annual Meeting of Stockholders, which the Registrant intends to file with the
Securities and Exchange Commission not later than 120 days after the end of the
fiscal year covered by this Form 10-K, are incorporated by reference into Part
III of this Form 10-K.
TABLE OF CONTENTS
PART I
Item 1. Business....................................................... 2
Item 2. Properties..................................................... 18
Item 3. Legal Proceedings.............................................. 19
Item 4. Submission of Matters to a Vote of Security Holders............ 19
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters........................................................ 20
Item 6. Selected Financial Data........................................ 21
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 23
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..... 32
Item 8. Financial Statements and Supplementary Data.................... 32
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure....................................... 32
Item 9a. Controls and Procedures........................................ 33
PART III
Item 10. Directors and Executive Officers of the Registrant............. 33
Item 11. Executive Compensation......................................... 33
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters..................... 34
Item 13. Certain Relationships and Related Transactions................. 34
Item 14. Principal Accounting Fees and Services......................... 34
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K............................................................ 34
SIGNATURES.................................................................. 38
INDEX TO COMBINED, PRO FORMA COMBINED AND CONSOLIDATED FINANCIAL
STATEMENTS.................................................................. 39
1
PART I
This Annual Report on Form 10-K contains forward-looking statements
within the meaning of Section 27A of the Securities Exchange Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Actual results could differ
materially from those projected in the forward-looking statements as a result of
a number of important factors. For a discussion of important factors that could
affect our results, please refer to "Item 1. Business" including the risk
factors discussed therein and the financial statement line item discussions set
forth in "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations" below.
ITEM 1. BUSINESS
OUR COMPANY
We are a leading provider of specialty products and services to oil and
gas drilling and production companies throughout the world. We operate in a
substantial number of the world's active oil and gas producing regions,
including the Gulf of Mexico, U.S. onshore, Canada, West Africa, the Middle
East, South America and Southeast Asia. Our customers include many of the major
and independent oil and gas companies and other oilfield service companies. We
operate in three principal business segments, offshore products, tubular
services and well site services, and have established a leadership position in
each.
General information about us can be found at www.oilstatesintl.com. Our
annual report on Form 10-K, quarterly reports on Form 10-Q and current reports
on Form 8-K, as well as any amendments and exhibits to those reports, are
available free of charge through our website as soon as reasonably practicable
after we file them with, or furnish them to, the SEC.
OUR BACKGROUND
Oil States International, Inc. was originally incorporated in July 1995
as CE Holdings, Inc. On August 1, 1995, CE Holdings, Inc. acquired Continental
Emsco Company, an operator of oilfield supply stores, including its then wholly
owned subsidiary Oil States Industries, Inc. (Oil States Industries). Oil States
Industries is a manufacturer of offshore products.
In May 1996, Oil States Industries purchased the construction division
of Hunting Oilfield Services, Ltd., which provides a variety of construction
products and services to the offshore oil and gas industry as well as certain
connector manufacturing technology. In November 1996, CE Holdings, Inc. changed
its name to CONEMSCO, Inc. (Conemsco).
In July 1997, Conemsco purchased HydroTech Systems, Inc., a full
service provider of engineered products to the offshore pipeline industry, and
SMATCO Industries Inc., a manufacturer of marine winches for the offshore
service boat industry. In December 1997, Conemsco purchased Gregory Rig Service
& Sales Inc., a provider of drilling equipment and services.
In February 1998, Conemsco acquired Subsea Ventures, Inc. (SVI). SVI
designs, manufactures and services auxiliary structures for subsea blowout
preventors and subsea production systems. In April 1998, Conemsco acquired the
assets of Klaper (UK) Limited, a provider of repair and maintenance services for
blowout preventors and drilling risers used in offshore drilling.
In July 2000, Conemsco changed its name to Oil States International,
Inc. In July 2000, Oil States International, Inc., HWC Energy Services, Inc.
(HWC), PTI Group Inc. (PTI) and Sooner Inc. (Sooner) entered into a Combination
Agreement (the Combination Agreement) providing that, concurrently with the
closing of our initial public offering, HWC, PTI and Sooner would merge with
wholly owned subsidiaries of Oil States (the Combination). As a result, HWC, PTI
and Sooner became wholly owned subsidiaries of Oil States in February 2001. In
this Annual Report on Form 10-K, references to the "Company" or to "we," "us,"
"our," and similar terms are to Oil States International, Inc. and its
subsidiaries following the Combination and references to "Oil States" are to Oil
States International, Inc. and its subsidiaries prior to the Combination.
2
In 2002, we acquired the following six businesses for total
consideration of approximately $72.0 million, which was financed primarily with
borrowings under our credit facility:
- Southeastern Rentals LLC, based in Mississippi, Edge Wireline
Rentals Inc. and certain affiliated companies, located in
Louisiana, and J.V. Oilfield Rentals & Supply, Inc. and
certain affiliated companies, located in Louisiana, all of
which are suppliers of rental tools to the oil and gas service
industry. These businesses were merged into our existing
rental tool business included in our well site services
segment.
- Barlow Hunt, Inc., based in Oklahoma, an elastomer molding
company which has become part of our existing elastomer
business included in the offshore products segment.
- Certain assets and related liabilities of Big Inch Marine
Services, Inc., a Texas-based subsidiary of Stolt Offshore,
Inc., which provides subsea pipeline equipment and repair
services similar to those provided by us in the offshore
products segment.
- Applied Hydraulic Systems, Inc., a Louisiana-based offshore
crane manufacturer and crane repair service provider, which
has become part of our offshore products segment.
In 2003, we spent $16.7 million, financed with borrowings under our
credit facility, to acquire five businesses. Three of the businesses were rental
tool companies acquired for a total consideration of $10.5 million. The acquired
rental tool companies conduct operations in South Texas and Louisiana and will
be combined with our existing rental tool business within our well site services
segment. The remaining two businesses, acquired for aggregate consideration of
$6.2 million, were combined with our offshore products segment.
In January 2004, the Company completed the acquisition of several
related rental tool companies. The companies, based in South Texas are leading
providers of thru-tubing services and ancillary equipment rentals. These
companies have been combined with our rental tool subsidiary, and will report
through the well site services segment. The Company paid a total of $34.7
million in cash for the stock of the companies which was funded by the Company's
credit facility.
OUR INDUSTRY
We operate in the oilfield service industry, which provides products
and services to oil and gas exploration and production companies for use in the
drilling for and production of oil and gas. Demand for our products and services
is cyclical and substantially dependent upon activity levels in the oil and gas
industry, particularly our customers' willingness to spend capital on the
exploration and development of oil and gas reserves. Demand for our products and
services by our customers is highly sensitive to current and expected oil and
natural gas prices. See Note 15 to our Consolidated and Combined Financial
Statements included in this Annual Report on Form 10-K for financial information
by segment and a geographical breakout of revenues and long-lived assets.
The years 2001 through 2003 were indicative of the cyclical nature of
the oilfield service business. For our well site services and tubular services
businesses, there was higher activity, as measured by the North American rig
count, during the first eight months of 2001 followed by declining activity
levels, except for seasonal winter peaks in Canadian activity, through the
spring of 2002. The average annual North American rig count declined 27% from
2001 to 2002. During 2003, the average North American rig count was 1,404 and
increased by 307 rigs, or 28%, compared to 2002. As of December 31, 2003 the
North American rig count was 1,531. See additional rig count information under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -Overview" in this Annual Report on Form 10-K. Our offshore products
business is more influenced by deepwater development activity and rig
construction and repair. Results of operations in this segment of our business
has increased throughout the years 2002 and 2003 as we shipped projects from our
backlog which had increased in 2001 and 2002.
3
OFFSHORE PRODUCTS
OVERVIEW
During the year ended December 31, 2003, we generated approximately 32%
of our revenue and 39% of our operating income, before corporate charges, from
our offshore products segment. Through this segment, we design and manufacture a
number of cost-effective, technologically advanced products for the offshore
energy industry. Our products and services are used in both shallow and
deepwater producing regions and include flex-element technology, advanced
connector systems, blow-out preventor stack integration and repair services,
deepwater mooring and lifting systems, offshore equipment and installation
services and subsea pipeline products. We have facilities in Arlington, Houston
and Lampasas, Texas; Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil;
England and Singapore that support our offshore products segment.
OFFSHORE PRODUCTS MARKET
The market for our offshore products and services depends primarily
upon development of infrastructure for offshore production activities, drilling
rig refurbishments and upgrades and new rig construction. As demand for oil and
gas increases and related drilling and production increases in offshore areas
throughout the world, particularly in deeper water, we expect spending on these
activities to increase.
The upgrade of existing rigs to equip them with the capability to drill
in deeper water, the construction of new deepwater-capable rigs, and the
installation of fixed or floating production systems require specialized
products and services like the ones we provide.
PRODUCTS AND SERVICES
Our offshore products segment provides a broad range of products and
services for use in offshore drilling and development activities. In addition,
this segment provides onshore oil and gas, defense and general industrial
products and services. Our offshore products segment is dependent on continuing
innovation and creative applications of existing technologies.
We design and build manufacturing and testing systems for many of our
new products and services. These testing and manufacturing facilities enable us
to provide reliable, technologically advanced products and services. Our
Aberdeen facility provides structural testing including full-scale product
simulations.
Offshore Development and Drilling Activities. We design, manufacture,
fabricate, inspect, assemble, repair, test and market subsea equipment and
offshore vessel and rig equipment. Our products are components of equipment used
for the drilling and production of oil and gas wells on offshore fixed platforms
and mobile production units, including floating platforms and floating
production, storage and offloading vessels, and on other marine vessels,
floating rigs and jack-ups. Our products and services include:
- flexible bearings and connector products;
- subsea pipeline products;
- marine winches, mooring and lifting systems and rig equipment;
- blowout preventor stack assembly, integration, testing and
repair services; and
- other products and services.
Flexible Bearings and Connector Products. We are the principal supplier
of flexible bearings, or FlexJoints(R), to the offshore oil and gas industry. We
also supply connections and fittings that join lengths of large diameter
conductor or casing used in offshore drilling operations. FlexJoints(R) are
flexible bearings that permit movement of riser pipes or tension leg platform
tethers under high tension and pressure. They are used on drilling, production
and export risers and are used increasingly as offshore production moves to
deeper water areas. Drilling riser systems
4
provide the vertical conduit between the floating drilling vessel and the subsea
wellhead. Through the drilling riser, equipment is guided into the well and
drilling fluids are returned to the surface. Production riser systems provide
the vertical conduit from the subsea wellhead to the floating production
platform. Oil and gas flows to the surface for processing through the production
riser. Export risers provide the vertical conduit from the floating production
platform to the subsea export pipelines. FlexJoints(R) are a critical element in
the construction and operation of production and export risers on floating
production systems in deepwater.
Floating production systems, including tension leg platforms, Spars and
FPSO systems, are a significant means of producing oil and gas, particularly in
deepwater environments. We provide many important products for the construction
of these systems. A tension leg platform is a floating platform that is moored
by vertical pipes, or tethers, attached to both the platform and the sea floor.
Our FlexJoint(R) tether bearings are used at the top and bottom connections of
each of the tethers, and our Merlin connectors are used to join shorter pipe
segments to form long pipes offshore. A Spar is a floating vertical cylindrical
structure which is approximately six to seven times longer than its diameter and
is anchored in place.
Subsea Pipeline Products. We design and manufacture a variety of
fittings and connectors used in offshore oil and gas pipelines. Our products are
used for new construction, maintenance and repair applications. New construction
fittings include:
- forged steel Y-shaped connectors for joining two pipelines
into one;
- pressure-balanced safety joints for protecting pipelines from
anchor snags or a shifting sea-bottom;
- electrical isolation joints; and
- hot tap clamps that allow new pipelines to be joined into
existing lines without interrupting the flow of petroleum
product.
We provide diverless connection systems for subsea flowlines and
pipelines. Our HydroTech collet connectors provide a high-integrity, proprietary
metal-to-metal sealing system for the final hook-up of deep offshore pipelines
and production systems. They also are used in diverless pipeline repair systems
and in future pipeline tie-in systems. Our lateral tie-in sled, which is
installed with the original pipeline, allows a subsea tie-in to be made quickly
and efficiently using proven HydroTech connectors without costly offshore
equipment mobilization and without shutting off product flow.
We provide pipeline repair hardware, including deepwater applications
beyond the depth of diver intervention. Our products include:
- repair clamps used to seal leaks and restore the structural
integrity of a pipeline;
- mechanical connectors used in repairing subsea pipelines
without having to weld;
- flanges used to correct misalignment and swivel ring flanges;
and
- pipe recovery tools for recovering dropped or damaged
pipelines.
Marine Winches, Mooring and Lifting Systems and Rig Equipment. We
design, engineer and manufacture marine winches, mooring and lifting systems and
rig equipment. Our Skagit winches are specifically designed for mooring floating
and semi-submersible drilling rigs and positioning pipelay and derrick barges,
anchor handling boats and jack-ups, while our Nautilus marine cranes are used on
production platforms throughout the world. We also design and fabricate rig
equipment such as automatic pipe racking and blow-out preventor handling
equipment. Our engineering teams, manufacturing capability and service
technicians who install and service our products provide our customers with a
broad range of equipment and services to support their operations. Aftermarket
service and support of our installed base of equipment to our customers is also
an important source of revenues to us.
5
BOP Stack Assembly, Integration, Testing and Repair Services. We design
and fabricate lifting and protection frames and offer system integration of
blow-out preventor stacks and subsea production trees. We can provide complete
turnkey and design fabrication services. We also design and manufacture a
variety of custom subsea equipment, such as riser flotation tank systems, guide
bases, running tools and manifolds. In addition, we also offer blow-out
preventor and drilling riser testing and repair services.
Other Products and Services. We provide equipment for securing subsea
structures and offshore platform jackets, including our Hydra-Lok(R) hydraulic
system. The Hydra-Lok(R) tool, which has been successfully used at depths of
3,000 feet, does not require diver intervention or guidelines.
We also provide cost-effective, standardized leveling systems for
offshore structures that are anchored by foundation piles, including subsea
templates, subsea manifolds and platform jackets.
Our offshore products segment also produces a variety of products for
use in applications other than in the offshore oil and gas industry. For
example, we provide:
- elastomer consumable downhole products for onshore drilling
and production;
- metal-elastomeric FlexJoints(R) used in a variety of military,
marine and aircraft applications; and
- drum-clutches and brakes for heavy-duty power transmission in
the mining, paper, logging and marine industries.
Backlog. Backlog in our offshore products segment was $62.6 million at
December 31, 2003, compared to $100.1 million at December 31, 2002 and $72.4
million at December 31, 2001. We expect substantially all our backlog as of
December 31, 2003 will be completed in 2004. Our offshore products backlog
consists of firm customer purchase orders for which satisfactory credit or
financing arrangements exist and delivery is scheduled. In some instances, these
purchase orders are cancelable by the customer, subject to the payment of
termination fees and/or the reimbursement of our costs incurred. Although our
backlog is an important indicator of future offshore products shipments and
revenues, backlog as of any particular date may not be indicative of our actual
operating results for any future period. We believe that the offshore
construction and development business is characterized by lengthy projects and a
long "lead-time" order cycle. The change in backlog levels from one period to
the next does not necessarily evidence a long-term trend.
REGIONS OF OPERATIONS
Our offshore products segment provides products and services to
customers in the major offshore oil and gas producing regions of the world,
including the Gulf of Mexico, West Africa, the North Sea, Brazil and Southeast
Asia.
CUSTOMERS AND COMPETITORS
We market our products and services to a broad customer base, including
the direct end users, engineering and design companies, prime contractors, and
at times, our competitors through outsourcing arrangements.
Our three largest customers in the offshore products markets in 2003
were ABB Ltd, BP plc and Modec International. None of these customers accounted
for greater than 5% of our consolidated revenues during 2003. Our main
competitors include ABB Ltd, FMC Technologies, Inc., Energy Cranes
International, Ltd. and Rolls-Royce plc.
6
TUBULAR SERVICES
OVERVIEW
On February 14, 2001, the Company completed its acquisition of Sooner.
Sooner's business is reported as our tubular services segment.
During the year ended December 31, 2003, we generated approximately 33%
of our revenue and 9% of our operating income, before corporate charges, from
our tubular services segment. Through this segment, we distribute oil country
tubular goods, or OCTG, and provide associated OCTG finishing and logistics
services to the oil and gas industry. Oil country tubular goods consist of
downhole casing and production tubing. Through our tubular services segment, we:
- distribute a broad range of casing and tubing;
- provide threading, remediation, logistical and inventory
services; and
- offer e-commerce pricing, ordering and tracking capabilities.
We serve a customer base ranging from major oil companies to small
independents. Through our key relationships with more than 20 domestic and
foreign manufacturers and related service providers of OCTG, we deliver tubular
products and ancillary services to oil and gas companies, drilling contractors
and consultants predominantly in the United States. The OCTG distribution market
is highly fragmented and competitive, and is predominately focused in the United
States.
OCTG MARKET
Our tubular services segment primarily distributes casing and tubing.
Casing forms the structural wall in oil and gas wells to provide support and
prevent caving during drilling operations. Casing is used to protect water-
bearing formations during the drilling of a well. Casing is generally not
removed after it has been installed in a well. Production tubing, which is used
to bring oil and gas to the surface, may be replaced during the life of a
producing well.
A key indicator of domestic demand for OCTG is the average number of
drilling rigs operating in the United States. The OCTG market at any point in
time is also affected by the level of inventories maintained by manufacturers,
distributors and end users. Demand for tubular products is positively impacted
by increased drilling of deeper, horizontal and offshore wells. Deeper wells
require incremental tubular footage and enhanced mechanical capabilities to
ensure the integrity of the well. Premium tubulars are used in horizontal
drilling to withstand the increased bending and compression loading associated
with a horizontal well. Operators typically specify premium tubulars for the
completion of offshore wells.
PRODUCTS AND SERVICES
Tubular Products and Services. We distribute various types of OCTG
produced by both domestic and foreign manufacturers to major and independent oil
and gas exploration and production companies and other OCTG distributors. We do
not manufacture any of the tubular goods that we distribute. As a result, gross
margins in this segment are generally lower than those reported by our other
segments. We operate our tubular services segment from a total of five offices
and facilities located near areas of oil and gas exploration and development
activity. We have distribution relationships with most major domestic and
international steel mills.
In this business, inventory management is critical to our success. We
maintain on-the-ground inventory in 58 yards located in the United States,
giving us the flexibility to fill our customers' orders from our own stock or
directly from the manufacturer. We have a proprietary inventory management
system, designed specifically for the OCTG industry, that enables us to track
our product shipments down to the individual joint of pipe.
7
A-Z Terminal. Our A-Z Terminal pipe maintenance and storage facility in
Crosby, Texas is equipped to provide a full range of tubular services, giving us
strong customer service capabilities. Our A-Z Terminal is on 109 acres, is an
ISO 9001-certified facility and has more than 1,400 pipe racks and two
double-ended thread lines. We have exclusive use of a permanent third-party
inspection center within the facility. The facility also includes indoor chrome
storage capability and patented pipe cleaning machines.
We offer services at our A-Z Terminal facility typically outsourced by
other distributors, including the following: threading, inspection, cleaning,
cutting, logistics, rig returns, installation of float equipment and
non-destructive testing.
Tubular Products and Services Sales Arrangements. We provide our
tubular products and logistics services through a variety of arrangements,
including spot market sales and alliances. We provide some of our tubular
products and services to independent and major oil and gas companies under
alliance arrangements. Although our alliances are generally not as profitable as
the spot market and can be cancelled by the customer, they provide us with more
stable and predictable revenues and an improved ability to forecast required
inventory levels, which allows us to manage our inventory more efficiently.
REGIONS OF OPERATIONS
Our tubular services segment provides tubular products and services
principally to customers in the United States both for land and offshore
applications. However, we also sell for export to other countries, including
Canada, Venezuela, Ecuador, Algeria, South Africa and Cameroon.
CUSTOMERS, SUPPLIERS AND COMPETITORS
Our three largest end-user customers in the tubular distribution market
in 2003 were El Paso Corporation, Burlington Resources and Conoco Phillips. El
Paso Corporation revenues for all of our segments accounted for 6.5% of our
consolidated revenues during 2003. Conoco Phillips and Burlington Resources each
accounted for less than 5% of our consolidated revenues during 2003. Our three
largest suppliers were U.S. Steel Group, Maverick Tube Corporation and Lone Star
Technologies. Although we have a leading market share position in tubular
services distribution, the market is highly fragmented. Our main competitors in
tubular distribution are Total Premier, Red Man Pipe & Supply Co., Inc. and
Bourland and Leverich.
WELL SITE SERVICES
OVERVIEW
During the year ended December 31, 2003, we generated approximately 35%
of our revenue and 52% of our operating income, before corporate charges, from
our well site services segment. Our well site services segment provides a broad
range of products and services that are used to establish and maintain the flow
of oil and gas from a well throughout its lifecycle. Our services include
workover services, drilling services, rental equipment, work force
accommodations, catering and logistics services and modular building
construction services. We use our fleet of workover and drilling rigs, rental
equipment, work force accommodation facilities and related equipment to service
well sites for oil and natural gas companies. Our products and services are used
in both onshore and offshore applications through the exploration, development,
production and abandonment phases of a well's life. Additionally, our work force
accommodations, catering and logistics services are employed in a variety of
mining and related natural resource applications as well as forest fire
fighting.
WELL SITE SERVICES MARKET
Demand for our workover and drilling rigs, rental equipment and work
force accommodations, catering and logistics services has historically been tied
to the level of expenditures by oil and gas producers which is a function of
prices they receive for oil and gas. In general, we expect activity levels to
continue to be highly correlated to oil and gas expenditures which is a function
of many factors that affect well economics.
8
Demand for our workover services is impacted significantly by offshore
activity both in the United States and international areas. Our hydraulic
workover units compete with jackup rigs and conventional workover rigs for
shallow water workover projects. Our hydraulic workover units can be operated,
at times, at a lower cost than alternatives such as jack-up rigs. Costs to
mobilize and set up our hydraulic workover units, for example, are lower than
alternative equipment. Some operations on oil and gas wells under pressure
situations require the use of a hydraulic workover unit. On the other hand, when
activity levels in the oil and gas business decline, our hydraulic units face
more competition from larger equipment offered at lower prices which can become
more competitive with our equipment.
Our rental equipment fleet which is predominantly located near the U.S.
Gulf of Mexico market, is more production oriented and is dependent to a
significant degree on the level of development and workover activities in the
U.S. Gulf Coast area and the Gulf of Mexico. We face competition from many
smaller companies in our rental equipment business in the U.S. Gulf of Mexico
market. The lack of increased drilling in the U.S. Gulf of Mexico has resulted
in a lower than anticipated increase in rental tool revenues and profitability
in 2003.
PRODUCTS AND SERVICES
Workover Services. We provide our workover products and services
primarily to customers in the U.S., Venezuela, the Middle East and West Africa,
for both onshore and offshore applications. Workover products and services are
used in operations on a producing well to restore or increase production.
Workover services are typically used during the development, production and
abandonment stages of the well. Our hydraulic workover units are used for
workover operations and snubbing operations in pressure situations.
A hydraulic workover unit is a specially designed rig used for
vertically moving tubulars in and out of a wellbore using hydraulic pressure.
This unit is used for servicing wells with no pressure at the surface and also
has the ability of working safely on wells under pressure. This feature allows
these units to be used for underbalanced drilling and workover and also in well
control applications. When the unit is snubbing, it is pushing pipe or tubulars
into the well bore against well bore pressures. Because of their small size and
ability to work on wells under pressure, hydraulic workover units offer some
advantages over larger workover rigs and conventional drilling rigs. However,
most wells where we perform workover service are wells with no pressure.
As of December 31, 2003 we had 28 "stand alone" hydraulic workover
units. Of these 28 units, 16 were located in the U.S., five were located in the
Middle East, five were located in Venezuela and two were located in West Africa.
In addition, we had labor and maintenance contracts on two non-owned hydraulic
workover units in Algeria. Typically, our hydraulic workover units are
contracted on a short-term dayrate basis. As a result, utilization of our
hydraulic workover units varies from period to period. Our utilization rate for
hydraulic workover units was 30.7% during 2003 compared to 28.5% in 2002. As of
December 31, 2003, nine of our hydraulic workover units were working or under
contract. The length of time to complete a job depends on many factors,
including the number of wells and the type of workover or pressure control
situation involved. Usage of our hydraulic workover units is also affected by
the availability of trained personnel. With our current level of trained
personnel, we estimate that we have the capability to crew and operate 10 to 12
simultaneous jobs involving our hydraulic workover units.
Our three largest customers in workover services in 2003 were
Sonatrach, Chevron Texaco Corporation and Total Fina Elf. None of these
customers accounted for greater than 5% of our consolidated revenues during
2003. Our main competitors in workover services are Halliburton Company, Cudd
Pressure Control, Inc. and Superior Energy Services.
Drilling Services. Our drilling services business is located in Odessa,
Texas and Wooster, Ohio and provides drilling services for shallow to medium
depths ranging from 2,000 to 10,000 feet. Drilling services are typically used
during the exploration and development stages of a field. We have a total of 17
semi-automatic drilling rigs with hydraulic pipe handling booms and lift
capacities ranging from 200,000 to 300,000 pounds. We added three of these
drilling rigs in 2002, one in December 2003 and one in February 2004. Thirteen
of these drilling rigs are located in Odessa, Texas and four are located in
Wooster, Ohio. As of December 31, 2003, 15 rigs were working or under contract.
Utilization increased from 85.6% in 2002 to 88.4% in 2003.
We market our drilling services directly to a diverse customer base,
consisting of both major and independent oil companies. Our largest customers in
drilling services in 2003 included Energen Resources Corporation, Apache
9
Corporation and Chevron Texaco Corporation. None of these customers accounted
for greater than 5% of our consolidated revenues. Our main competitors are
Patterson-UTI Energy Inc., Key Energy Services, Inc. and Union Drilling, Inc.
The land drilling business is highly fragmented and consists of a small number
of large companies and many smaller companies.
Rental Equipment. Our rental equipment business provides a wide range
of products for use in the offshore and onshore oil and gas industry, including:
- wireline and coiled tubing pressure control equipment;
- pipe recovery systems;
- gravel pack operations on well bores; and,
- surface control equipment and down-hole tools utilized by
coiled tubing operators.
Our rental equipment is used during the exploration, development,
production and abandonment stages. As of December 31, 2003, we provided rental
equipment at 21 U.S. distribution points in Texas, Louisiana, Oklahoma,
Mississippi, New Mexico and Wyoming, an increase of four locations since
December 31, 2002. We completed rental tool acquisitions totaling $10.5 million
during 2003 and $34.7 million during January 2004. We provide rental equipment
on a day rental basis with rates varying depending on the type of equipment and
the length of time rented.
Our three largest customers in rental equipment in 2003 were
Schlumberger Well Services, Baker Atlas and BP plc. None of these customers
accounted for greater than 5% of our consolidated revenues during 2003.
Work Force Accommodations, Catering and Logistics and Modular Building
Construction. We are a large provider of integrated products and services to
support workers in remote locations, including work force accommodation, food
services, remote site management services and modular building construction. We
provide complete design, manufacture, installation, operation and redeployment
logistics services for oil and gas drilling, oil sands mining in the Fort
McMurray region of Northern Canada, diamond mining in Northern Canada and other
mining ventures throughout the world, pipeline construction, forestry, offshore
construction, disaster relief services and support services for military
operations on a worldwide basis. Our work force products and service operations
are primarily focused in Canada and the Gulf of Mexico although we have
activity, currently, in Afghanistan and the Balkans, serving the Canadian
peacekeeping forces. During the peak of our operating season, we typically
provide these services in over 200 separate locations throughout the world with
separate location populations ranging from 20 to 2000 persons.
Work Force Accommodations, Catering and Logistics Services. We sell and
lease portable living quarters, galleys, diners and offices and provide portable
generators, water, sewage systems and catering services as part of our work
force services. We provide various client-specific building configurations to
customers for use in both onshore and offshore applications. We provide our
integrated work force logistics services to customers under long-term and
short-term contractual arrangements.
Modular Building Construction. We design, construct and install a
variety of portable modular buildings, including housing, kitchens, recreational
units and offices for lease or sale to the Canadian and Gulf of Mexico markets.
Our designers work closely with our clients to build structures that best serve
their needs.
In 2003 our three largest customers in work force accommodations,
catering, logistics and modular building construction were Syncrude Canada Ltd,
SNC-Lavalin Group Inc. and Nabors Drilling. None of these customers accounted
for greater than 5% of our consolidated revenues during 2003. Our main
competitors are Atco Structures Limited, Eurest Deutschland GmbH, Aramark
Corporation and Abbyville Offshore Inc.
EMPLOYEES
As of December 31, 2003, we had approximately 3,900 full-time
employees, 35% of whom are in our offshore products segment, 63% of whom are in
our well site services segment and 2% of whom are in our tubular services
10
segment. We are party to collective bargaining agreements covering 452
employees located in Canada and the United Kingdom as of December 31, 2003. We
believe relations with our employees are good.
GOVERNMENT REGULATION
Our business is significantly affected by foreign, federal, state and
local laws and regulations relating to the oil and natural gas industry, worker
safety and environmental protection. Changes in these laws, including more
stringent administrative regulations and increased levels of enforcement of
these laws and regulations, could significantly affect our business. We cannot
predict changes in the level of enforcement of existing laws and regulations or
how these laws and regulations may be interpreted or the effect changes in these
laws and regulations may have on us or our future operations or earnings. We
also are not able to predict whether additional laws and regulations will be
adopted.
We depend on the demand for our products and services from oil and
natural gas companies. This demand is affected by changing taxes, price controls
and other laws and regulations relating to the oil and gas industry generally,
including those specifically directed to oilfield and offshore operations. The
adoption of laws and regulations curtailing exploration and development drilling
for oil and natural gas in our areas of operation could also adversely affect
our operations by limiting demand for our products and services. We cannot
determine the extent to which our future operations and earnings may be affected
by new legislation, new regulations or changes in existing regulations or
enforcement.
Some of our employees who perform services on offshore platforms and
vessels are covered by the provisions of the Jones Act, the Death on the High
Seas Act and general maritime law. These laws operate to make the liability
limits established under states' workers' compensation laws inapplicable to
these employees and permit them or their representatives generally to pursue
actions against us for damages or job-related injuries with no limitations on
our potential liability.
Our operations are subject to numerous foreign, federal, state and
local environmental laws and regulations governing the release and/or discharge
of materials into the environment or otherwise relating to environmental
protection. Numerous governmental agencies issue regulations to implement and
enforce these laws, for which compliance is often costly and difficult. The
violation of these laws and regulations may result in the denial or revocation
of permits, issuance of corrective action orders, assessment of administrative
and civil penalties, and even criminal prosecution. We believe that we are in
substantial compliance with applicable environmental laws and regulations.
Further, we do not anticipate that compliance with existing environmental laws
and regulations will have a material effect on our consolidated financial
statements.
We generate wastes, including hazardous wastes, that are subject to the
federal Resource Conservation and Recovery Act, or RCRA, and comparable state
statutes. The United States Environmental Protection Agency, or EPA, and state
agencies have limited the approved methods of disposal for some types of
hazardous and nonhazardous wastes. Some wastes handled by us in our field
service activities that currently are exempt from treatment as hazardous wastes
may in the future be designated as "hazardous wastes" under RCRA or other
applicable statutes. This would subject us to more rigorous and costly operating
and disposal requirements.
The federal Comprehensive Environmental Response, Compensation, and
Liability Act, or CERCLA or the "Superfund" law, and comparable state statutes
impose liability, without regard to fault or legality of the original conduct,
on classes of persons that are considered to have contributed to the release of
a hazardous substance into the environment. These persons include the owner or
operator of the disposal site or the site where the release occurred and
companies that disposed of or arranged for the disposal of the hazardous
substances at the site where the release occurred. Under CERCLA, these persons
may be subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. We
currently have operations on properties where activities involving the handling
of hazardous substances or wastes may have been conducted prior to our
operations on such properties or by third parties whose operations were not
under our control. These properties may be subject to CERCLA, RCRA and analogous
state laws. Under these laws and related regulations, we could be required to
remove or remediate previously discarded hazardous substances and
11
wastes or property contamination that was caused by these third parties. These
laws and regulations may also expose us to liability for our acts that were in
compliance with applicable laws at the time the acts were performed.
The Federal Water Pollution Control Act and analogous state laws impose
restrictions and strict controls regarding the discharge of pollutants into
state waters or waters of the United States. The discharge of pollutants into
jurisdictional waters is prohibited unless the discharge is permitted by the EPA
or applicable state agencies. Many of our properties and operations require
permits for discharges of wastewater and/or stormwater, and we have a system for
securing and maintaining these permits. In addition, the Oil Pollution Act of
1990 imposes a variety of requirements on responsible parties related to the
prevention of oil spills and liability for damages, including natural resource
damages, resulting from such spills in waters of the United States. A
responsible party includes the owner or operator of a facility or vessel, or the
lessee or permittee of the area in which an offshore facility is located. The
Federal Water Pollution Control Act and analogous state laws provide for
administrative, civil and criminal penalties for unauthorized discharges and,
together with the Oil Pollution Act, impose rigorous requirements for spill
prevention and response planning, as well as substantial potential liability for
the costs of removal, remediation, and damages in connection with any
unauthorized discharges.
Some of our operations also result in emissions of regulated air
pollutants. The federal Clean Air Act and analogous state laws require permits
for facilities that have the potential to emit substances into the atmosphere
that could adversely affect environmental quality. Failure to obtain a permit or
to comply with permit requirements could result in the imposition of substantial
administrative, civil and even criminal penalties.
Although we believe that we are in substantial compliance with existing
laws and regulations, there can be no assurance that substantial costs for
compliance will not be incurred in the future. Moreover, it is possible that
other developments, such as the adoption of stricter environmental laws,
regulations and enforcement policies, could result in additional costs or
liabilities that we cannot currently quantify.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
We include the following cautionary statement to take advantage of the
"safe harbor" provisions of the Private Securities Litigation Reform Act of 1995
for any forward-looking statement made by us, or on our behalf. The factors
identified in this cautionary statement are important factors (but not
necessarily all of the important factors) that could cause actual results to
differ materially from those expressed in any forward-looking statement made by
us, or on our behalf. You can typically identify forward-looking statements by
the use of forward-looking words such as "may," "will," "could," "project,"
"believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast,"
and other similar words. All statements other than statements of historical
facts contained in this Annual Report on Form 10-K, including statements
regarding our future financial position, budgets, capital expenditures,
projected costs, plans and objectives of management for future operations and
possible future acquisitions, are forward-looking statements. Where any such
forward-looking statement includes a statement of the assumptions or bases
underlying such forward-looking statement, we caution that, while we believe
such assumptions or bases to be reasonable and make them in good faith, assumed
facts or bases almost always vary from actual results. The differences between
assumed facts or bases and actual results can be material, depending upon the
circumstances.
Where, in any forward-looking statement, we, or our management, express
an expectation or belief as to the future results, such expectation or belief is
expressed in good faith and believed to have a reasonable basis. However, there
can be no assurance that the statement of expectation or belief will result or
be achieved or accomplished. Taking this into account, the following are
identified as important factors that could cause actual results to differ
materially from those expressed in any forward-looking statement made by, or on
behalf of, our company:
- fluctuations in the prices of oil and gas;
- the level of drilling activity;
- the level of offshore oil and gas developmental activities;
- general economic conditions;
12
- our ability to find and retain skilled personnel;
- the availability of capital; and
- the other factors identified under the captions "Risks Related
to Our Business Generally" and "Risks Related to Our
Operations" that follow.
RISKS RELATED TO OUR BUSINESS GENERALLY
DECREASED OIL AND GAS INDUSTRY EXPENDITURE LEVELS WILL ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS.
We depend upon the oil and gas industry and its ability and willingness
to make expenditures to explore for, develop and produce oil and gas. If these
expenditures decline, our business will suffer. The industry's willingness to
explore, develop and produce depends largely upon the availability of attractive
drilling prospects and the prevailing view of future product prices. Many
factors affect the supply and demand for oil and gas and therefore influence
product prices, including:
- the level of production;
- the levels of oil and gas inventories;
- the expected cost of developing new reserves;
- the cost of producing oil and gas;
- the availability of attractive oil and gas field prospects
which may be affected by governmental actions or environmental
activists which may restrict drilling;
- the availability of transportation infrastructure;
- depletion rates;
- the level of drilling activity;
- worldwide economic activity;
- national government political requirements, including the
ability of the Organization of Petroleum Exporting Companies
(OPEC) to set and maintain production levels and prices for
oil;
- the impact of armed hostilities involving one or more oil
producing nations;
- the cost of developing alternate energy sources;
- environmental regulation; and
- tax policies.
EXTENDED PERIODS OF LOW OIL PRICES MAY DECREASE DEEPWATER EXPLORATION AND
PRODUCTION ACTIVITY AND ADVERSELY AFFECT OUR BUSINESS.
Our offshore products segment depends on exploration and production
expenditures in deepwater areas. Because deepwater projects are more capital
intensive and take longer to generate first production than shallow water and
onshore projects, the economic analyses conducted by exploration and production
companies typically assume lower prices for production from such projects to
determine economic viability over the long term. If oil prices remain near
13
or below those levels used to determine economic viability for an extended
period of time, deepwater activity and our business will be adversely affected.
BECAUSE THE OIL AND GAS INDUSTRY IS CYCLICAL, OUR OPERATING RESULTS MAY
FLUCTUATE.
Oil prices have been and are expected to remain volatile. This
volatility causes oil and gas companies and drilling contractors to change their
strategies and expenditure levels. We have experienced in the past, and we may
experience in the future, significant fluctuations in operating results based on
these changes.
DISRUPTIONS IN THE POLITICAL AND ECONOMIC CONDITIONS OF THE FOREIGN COUNTRIES IN
WHICH WE OPERATE COULD ADVERSELY AFFECT OUR BUSINESS.
We have operations in various international areas, including parts of
Africa, South America and the Middle East. Our operations in these areas
increase our exposure to risks of war, terrorist attacks, local economic
conditions, political disruption, civil disturbance and governmental policies
that may:
- disrupt our operations;
- restrict the movement of funds or limit repatriation of
profits;
- lead to U.S. government or international sanctions; and
- limit access to markets for periods of time.
WE MIGHT BE UNABLE TO EMPLOY A SUFFICIENT NUMBER OF TECHNICAL PERSONNEL.
Many of the products that we sell, especially in our offshore products
segment, are complex and highly engineered and often must perform in harsh
conditions. We believe that our success depends upon our ability to employ and
retain technical personnel with the ability to design, utilize and enhance these
products. In addition, our ability to expand our operations depends in part on
our ability to increase our skilled labor force. The demand for skilled workers
is high, and the supply is limited. A significant increase in the wages paid by
competing employers could result in a reduction of our skilled labor force,
increases in the wage rates that we must pay or both. If either of these events
were to occur, our cost structure could increase and our growth potential could
be impaired.
THE LEVEL AND PRICING OF TUBULAR GOODS IMPORTED INTO THE UNITED STATES COULD
DECREASE DEMAND FOR OUR TUBULAR GOODS INVENTORY AND ADVERSELY IMPACT OUR RESULTS
OF OPERATIONS. ALSO, IF STEEL MILLS WERE TO SELL A SUBSTANTIAL AMOUNT OF GOODS
DIRECTLY TO CUSTOMERS IN THE UNITED STATES, OUR RESULTS OF OPERATIONS COULD BE
ADVERSELY IMPACTED.
U.S. law currently restricts imports of low-cost tubular goods from a
number of foreign countries into the U.S. tubular goods market, resulting in
higher prices for tubular goods. If these restrictions were to be lifted or if
the level of imported low-cost tubular goods were to otherwise increase, our
tubular services segment could be adversely affected to the extent that we then
have higher-cost tubular goods in inventory. If prices were to decrease
significantly, we might not be able to profitably sell our inventory of tubular
goods. In addition, significant price decreases could result in a longer holding
period for some of our inventory, which could also have a material adverse
effect on our tubular services segment.
We do not manufacture any of the tubular goods that we distribute.
Historically, users of tubular goods in the United States, in contrast to
outside the United States, have purchased tubular goods from a distributor. If
customers were to purchase tubular goods directly from steel mills, our results
of operations could be adversely impacted.
WE ARE SUBJECT TO EXTENSIVE AND COSTLY ENVIRONMENTAL LAWS AND REGULATIONS THAT
MAY REQUIRE US TO TAKE ACTIONS THAT WILL ADVERSELY AFFECT OUR RESULTS OF
OPERATIONS.
Our hydraulic well control and drilling operations and our offshore
products business are significantly affected by stringent and complex foreign,
federal, state and local laws and regulations governing the discharge of
substances into the environment or otherwise relating to environmental
protection. We could be exposed to liability for cleanup
14
costs, natural resource damages and other damages as a result of our conduct
that was lawful at the time it occurred or the conduct of, or conditions caused
by, prior operators or other third parties. Environmental laws and regulations
have changed in the past, and they are likely to change in the future. If
existing regulatory requirements or enforcement policies change, we may be
required to make significant unanticipated capital and operating expenditures.
Any failure by us to comply with applicable environmental laws and
regulations may result in governmental authorities taking actions against our
business that could adversely impact our operations and financial condition,
including the:
- issuance of administrative, civil and criminal penalties;
- denial or revocation of permits or other authorizations;
- reduction or cessation in operations; and
- performance of site investigatory, remedial or other
corrective actions.
WE MAY NOT HAVE ADEQUATE INSURANCE FOR POTENTIAL LIABILITIES.
Our operations are subject to many hazards. We face the following risks
under our insurance coverage:
- we may not be able to continue to obtain insurance on
commercially reasonable terms;
- we may be faced with types of liabilities that will not be
covered by our insurance, such as damages from environmental
contamination or terrorist attacks;
- the dollar amount of any liabilities may exceed our policy
limits; and
- we may incur losses from interruption of our business that
exceed our insurance coverage.
Even a partially uninsured claim, if successful and of significant size, could
have a material adverse effect on our results of operations or consolidated
financial position.
WE ARE SUBJECT TO LITIGATION RISKS THAT MAY NOT BE COVERED BY INSURANCE.
In the ordinary course of business, we become the subject of various
claims, lawsuits and administrative proceedings seeking damages or other
remedies concerning our commercial operations, products, employees and other
matters, including occasional claims by individuals alleging exposure to
hazardous materials as a result of our products or operations. Some of these
claims relate to the activities of businesses that we have sold, and some relate
to the activities of businesses that we have acquired, even though these
activities may have occurred prior to our acquisition of such businesses. We
maintain insurance to cover many of our potential losses, and we are subject to
various self-retentions and deductibles under our insurance. It is possible,
however, that a judgment could be rendered against us in cases in which we could
be uninsured and beyond the amounts that we currently have reserved or
anticipate incurring for such matters.
WE MIGHT BE UNABLE TO COMPETE SUCCESSFULLY WITH OTHER COMPANIES IN OUR INDUSTRY.
We sell our products and services in competitive markets. In some of
our business segments, we compete with the oil and gas industry's largest
oilfield services providers. These companies have greater financial resources
than we do. In addition, our business, particularly our tubular services
business, may face competition from business-to-business internet auction
activities. Our business will be adversely affected to the extent that these
providers are successful in reducing purchases of our products and services.
15
RISKS RELATED TO OUR OPERATIONS
WE ARE SUSCEPTIBLE TO SEASONAL EARNINGS VOLATILITY DUE TO ADVERSE WEATHER
CONDITIONS IN OUR REGIONS OF OPERATIONS.
Our operations are directly affected by seasonal differences in weather
in the areas in which we operate, most notably in Canada and the Gulf of Mexico.
Our Canadian work force accommodations, catering and logistics operations are
significantly focused on the winter months when the winter freeze in remote
regions permits exploration and production activity to occur. The spring thaw in
these frontier regions restricts operations in the spring months and, as a
result, adversely affects our operations and sales of products and services in
the second and third quarters. Our operations in the Gulf of Mexico are also
affected by weather patterns. Weather conditions in the Gulf Coast region
generally result in higher drilling activity in the spring, summer and fall
months with the lowest activity in the winter months. In addition, summer and
fall drilling activity can be restricted due to hurricanes and other storms
prevalent in the Gulf of Mexico and along the Gulf Coast. As a result, full year
results are not likely to be a direct multiple of any particular quarter or
combination of quarters.
WE MIGHT BE UNABLE TO PROTECT OUR INTELLECTUAL PROPERTY RIGHTS.
We rely on a variety of intellectual property rights that we use in our
offshore products and well site services segments, particularly our patents
relating to our FlexJoint(R) technology. We may not be able to successfully
preserve these intellectual property rights in the future and these rights could
be invalidated, circumvented or challenged. In addition, the laws of some
foreign countries in which our products and services may be sold do not protect
intellectual property rights to the same extent as the laws of the United
States. The failure of our company to protect our proprietary information and
any successful intellectual property challenges or infringement proceedings
against us could adversely affect our competitive position.
IF WE DO NOT DEVELOP NEW COMPETITIVE TECHNOLOGIES AND PRODUCTS, OUR BUSINESS AND
REVENUES MAY BE ADVERSELY AFFECTED.
The market for our offshore products is characterized by continual
technological developments to provide better performance in increasingly greater
depths and harsher conditions. If we are not able to design, develop and produce
commercially competitive products in a timely manner in response to changes in
technology, our business and revenues will be adversely affected.
LOSS OF KEY MEMBERS OF OUR MANAGEMENT COULD ADVERSELY AFFECT OUR BUSINESS.
We depend on the continued employment and performance of Douglas E.
Swanson and other key members of management. If any of our key managers resign
or become unable to continue in their present roles and are not adequately
replaced, our business operations could be materially adversely affected. We do
not maintain "key man" life insurance for any of our officers.
IF WE HAVE TO WRITE OFF A SIGNIFICANT AMOUNT OF GOODWILL, OUR EARNINGS WILL BE
NEGATIVELY AFFECTED.
As of December 31, 2003, goodwill represented approximately 31% of our
total assets. We have recorded goodwill because we paid more for some of our
businesses than the fair market value of the tangible and separately measurable
intangible net assets of those businesses. Current accounting standards, which
were effective January 1, 2002, require a periodic review of goodwill for
impairment in value and a non-cash charge against earnings with a corresponding
decrease in stockholders' equity if circumstances indicate that the carrying
amount will not be recoverable. See Note 5 to our Consolidated and Combined
Financial Statements included in this Annual Report on Form 10-K.
IF WE WERE TO LOSE A SIGNIFICANT SUPPLIER OF OUR TUBULAR GOODS, WE COULD BE
ADVERSELY AFFECTED.
During 2003, we purchased from a single supplier approximately 49% of
the tubular goods we distributed and from three suppliers approximately 75% of
such tubular goods. We do not have contracts with any of these suppliers. If we
were to lose any of these suppliers or if production at one or more of the
suppliers were interrupted, our tubular services segment and our overall
business, financial condition and results of operations could be
16
adversely affected. If the extent of the loss or interruption were sufficiently
large, the impact on us would be material.
RISKS RELATED TO OUR RELATIONSHIP WITH SCF
L.E. SIMMONS, THROUGH SCF, EFFECTIVELY CONTROLS THE OUTCOME OF STOCKHOLDER
VOTING AND MAY EXERCISE THIS VOTING POWER IN A MANNER ADVERSE TO OUR
STOCKHOLDERS.
SCF-III, L.P. and SCF-IV, L.P., private equity funds that focus on
investments in the energy industry (collectively, "SCF"), together hold
approximately 40% of the outstanding common stock of our company as of February
27, 2004. L.E. Simmons, the chairman of our board of directors, is the sole
owner of L.E. Simmons & Associates, Incorporated, the ultimate general partner
of SCF. Accordingly, Mr. Simmons, through his ownership of the ultimate general
partner of SCF, is in a position to effectively control the outcome of matters
requiring a stockholder vote, including the election of directors, adoption of
amendments to our certificate of incorporation or bylaws or approval of
transactions involving a change of control. The interests of Mr. Simmons may
differ from those of our stockholders, and SCF may vote its common stock in a
manner that may adversely affect our stockholders.
SCF'S OWNERSHIP INTEREST AND PROVISIONS CONTAINED IN OUR CERTIFICATE OF
INCORPORATION AND BYLAWS COULD DISCOURAGE A TAKEOVER ATTEMPT, WHICH MAY REDUCE
OR ELIMINATE THE LIKELIHOOD OF A CHANGE OF CONTROL TRANSACTION AND, THEREFORE,
THE ABILITY OF OUR STOCKHOLDERS TO SELL THEIR SHARES FOR A PREMIUM.
In addition to SCF's position of effective control, provisions
contained in our certificate of incorporation and bylaws, such as a classified
board, limitations on the removal of directors, on stockholder proposals at
meetings of stockholders and on stockholder action by written consent and the
inability of stockholders to call special meetings, could make it more difficult
for a third party to acquire control of our company. Our certificate of
incorporation also authorizes our board of directors to issue preferred stock
without stockholder approval. If our board of directors elects to issue
preferred stock, it could increase the difficulty for a third party to acquire
us, which may reduce or eliminate our stockholders' ability to sell their shares
of common stock at a premium.
TWO OF OUR DIRECTORS MAY HAVE CONFLICTS OF INTEREST BECAUSE THEY ARE ALSO
DIRECTORS OR OFFICERS OF SCF. THE RESOLUTION OF THESE CONFLICTS OF INTEREST MAY
NOT BE IN OUR OR OUR STOCKHOLDERS' BEST INTERESTS.
Two of our directors, L.E. Simmons and Andrew L. Waite, are also
current directors or officers of L.E. Simmons & Associates, Incorporated, the
ultimate general partner of SCF. This may create conflicts of interest because
these directors have responsibilities to SCF and its owners. Their duties as
directors or officers of L.E. Simmons & Associates, Incorporated may conflict
with their duties as directors of our company regarding business dealings
between SCF and us and other matters. The resolution of these conflicts may not
always be in our or our stockholders' best interest.
WE HAVE RENOUNCED ANY INTEREST IN SPECIFIED BUSINESS OPPORTUNITIES, AND SCF AND
ITS DIRECTOR NOMINEES ON OUR BOARD OF DIRECTORS GENERALLY HAVE NO OBLIGATION TO
OFFER US THOSE OPPORTUNITIES.
SCF has investments in other oilfield service companies that compete
with us, and SCF and its affiliates, other than our company, may invest in other
such companies in the future. We refer to SCF, its other affiliates and its
portfolio companies as the SCF group. Our certificate of incorporation provides
that, so long as SCF and its affiliates continue to own at least 20% of our
common stock, we renounce any interest in specified business opportunities. Our
certificate of incorporation also provides that if an opportunity in the
oilfield services industry is presented to a person who is a member of the SCF
group, including any of those individuals who also serves as SCF's director
nominee of our Company:
- no member of the SCF group or any of those individuals has any
obligation to communicate or offer the opportunity to us; and
- such entity or individual may pursue the opportunity as that
entity or individual sees fit, unless:
17
- it was presented to an SCF director nominee solely in that
person's capacity as a director of our company and no other
member of the SCF group independently received notice of or
otherwise identified such opportunity; or
- the opportunity was identified solely through the disclosure
of information by or on behalf of our Company.
These provisions of our certificate of incorporation may be amended only by an
affirmative vote of holders of at least 80% of our outstanding common stock. As
a result of these charter provisions, our future competitive position and growth
potential could be adversely affected.
THE AVAILABILITY OF SHARES OF OUR COMMON STOCK FOR FUTURE SALE COULD DEPRESS OUR
STOCK PRICE
Sales by SCF and other stockholders of a substantial number of shares of our
common stock in the public markets, or the perception that such sales might
occur, could have a material adverse effect on the price of our common stock or
could impair our ability to obtain capital through an offering of equity
securities. SCF has sold shares recently and may continue to sell shares in the
future.
ITEM 2. PROPERTIES
The following table presents information about our principal properties and
facilities. Except as indicated below, we own all of these properties or
facilities.
APPROXIMATE
SQUARE
LOCATION FOOTAGE/ACREAGE DESCRIPTION
- ---------------------------------- --------------- -----------------------------------------------------------
United States
Houston, Texas (lease).......... 3,095 Principal executive offices
Arlington, Texas................ 11,264 Offshore products business office
Arlington, Texas................ 55,853 Offshore products manufacturing facility
Arlington, Texas (lease)........ 63,272 Offshore products manufacturing facility
Arlington, Texas................ 44,780 Elastomer technology center for offshore products
Arlington, Texas................ 60,000 Molding and aerospace facilities for offshore products
Houston, Texas (lease).......... 25,638 Offshore products business office
Houston, Texas.................. 130,000 Offshore products manufacturing facility
Houston, Texas (lease).......... 38,260 Offshore products warehouse
Lampasas, Texas................. 47,500 Molding facility for offshore products
Tulsa, Oklahoma................. 65,000 Molding facility for offshore products
Houma, Louisiana................ 153,000 Offshore products manufacturing facility and yard
Houma, Louisiana (lease) 108,714 Offshore products manufacturing facility and yard
Crosby, Texas................... 109 acres Tubular yard
Belle Chasse, Louisiana......... 11 acres Accommodations manufacturing facility and yard
for well site services
Lafayette, Louisiana (lease).... 9 acres Accommodations equipment repair yard for well site services
Houma, Louisiana................ 24,000 Well control yard and office for well site services
Houma, Louisiana................ 8,400 Well control office and training for well site services
Broussard, Louisiana............ 19,000 Rental tool warehouse for well site services
Odessa, Texas................... 7,500 Office and warehouse in support of drilling
operations for well site services
Alvin, Texas.................... 20,450 Rental tool warehouse for well site services
International
18
APPROXIMATE
SQUARE
LOCATION FOOTAGE/ACREAGE DESCRIPTION
- ---------------------------------- --------------- -----------------------------------------------------------
Aberdeen, Scotland (lease)...... 68,400 Offshore products manufacturing facility
Bathgate, Scotland.............. 28,000 Offshore products manufacturing facility
Barrow, England................. 14,551 Offshore products manufacturing facility
Singapore, Asia (lease)......... 23,600 Offshore products manufacturing facility
Macae, Brazil (lease)........... 45,702 Offshore products manufacturing facility
Nisku, Alberta.................. 8.58 acres Accommodations manufacturing facility for well site services
Edmonton, Alberta............... 31,000 Accommodations office and warehouse for well site services
Spruce Grove, Alberta........... 15,000 Accommodations facility and equipment yard for well site
services
Grande Prairie, Alberta......... 14.69 acres Accommodations facility and equipment yard for well site
services
Peace River, Alberta (lease).... 80 acres Accommodations equipment yard for well site services
We have five tubular sales offices and a total of 21 rental tool supply
and distribution points in Texas, Louisiana, New Mexico, Mississippi, Oklahoma
and Wyoming. Most of these office locations provide sales, technical support and
personnel services to our customers. We also have various offices supporting our
business segments which are both owned and leased.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various pending or threatened claims, lawsuits and
administrative proceedings seeking damages or other remedies concerning our
commercial operations, products, employees and other matters, including
occasional claims by individuals alleging exposure to hazardous materials as a
result of our products or operations. Some of these claims relate to matters
occurring prior to our acquisition of businesses, and some relate to businesses
we have sold. In certain cases, we are entitled to indemnification from the
sellers of businesses and in other cases, we have indemnified the buyers of
businesses from us. Although we can give no assurance about the outcome of
pending legal and administrative proceedings and the effect such outcomes may
have on us, we believe that any ultimate liability resulting from the outcome of
such proceedings, to the extent not otherwise provided for or covered by
insurance, will not have a material adverse effect on our consolidated financial
position, results of operations or liquidity.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
fourth quarter of 2003.
19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK INFORMATION
Our authorized common stock consists of 200,000,000 shares of common
stock. There were 49,187,129 shares of common stock outstanding as of February
27, 2004, including 339,965 shares of common stock issuable upon exercise of
exchangeable shares of one of our Canadian subsidiaries. These exchangeable
shares, which were issued to certain former shareholders of PTI in the
Combination, are intended to have characteristics essentially equivalent to our
common stock prior to the exchange. For purposes of this Annual Report on Form
10-K, we have treated the shares of common stock issuable upon exchange of the
exchangeable shares as outstanding. The approximate number of record holders of
our common stock as of February 27, 2004 was 99. Our common stock is traded on
the New York Stock Exchange under the ticker symbol OIS. There was no public
market for our common stock before February 9, 2001. The closing price of our
common stock on February 27, 2004 was $13.62 per share.
The following table sets forth the range of high and low sale prices of
the Company's common stock.
SALES PRICE
------------------
HIGH LOW
-------- --------
2001:
First Quarter (from February 9, 2001 to March 31, 2001).......... $ 12.50 $ 9.00
Second Quarter..................................................... 15.00 8.95
Third Quarter...................................................... 10.40 5.80
Fourth Quarter..................................................... 9.95 5.99
2002:
First Quarter...................................................... 11.10 6.90
Second Quarter..................................................... 11.96 9.80
Third Quarter...................................................... 11.89 8.85
Fourth Quarter..................................................... 13.50 9.96
2003:
First Quarter...................................................... 13.16 10.43
Second Quarter..................................................... 13.85 9.95
Third Quarter...................................................... 12.79 10.73
Fourth Quarter..................................................... 14.84 11.85
2004:
First Quarter (through February 27, 2004).......................... 16.35 13.03
We have not declared or paid any cash dividends on our common stock
since our initial public offering and do not intend to declare or pay any cash
dividends on our common stock in the foreseeable future. Instead, we currently
intend to retain our earnings, if any, to finance our business and to use for
general corporate purposes. Furthermore, our existing credit facilities restrict
the payment of dividends. Any future determination as to the declaration and
payment of dividends will be at the discretion of our Board of Directors and
will depend on then existing conditions, including our financial condition,
results of operations, contractual restrictions, capital requirements, business
prospects and other factors that our Board of Directors considers relevant.
EQUITY COMPENSATION PLANS
The information relating to the Company's equity compensation plans
required by Item 5 is incorporated by reference to such information as set forth
in the Company's Definitive Proxy Statement for the 2004 Annual Meeting of
Stockholders and from Item 12. "Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters" contained herein.
20
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data on the following pages include selected
historical and unaudited pro forma financial information of our company as of
and for the years ended December 31, 2003, 2002, 2001, 2000, and 1999. The
following data should be read in conjunction with Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations and the
Company's financial statements, and related notes included in Item 8, Financial
Statements and Supplementary Data of this Annual Report on Form 10-K.
SELECTED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------------------
2001
2003 2002 2001 2000 1999 ------------ 2000 1999
--------- -------- --------- --------- -------- CONSOLIDATED --------- ---------
CONSOLIDATED PRO FORMA (1) AND COMBINED COMBINED
---------------------- --------------------------------- ------------ ---------------------
Statements of Operations
Data:
Revenue.................. $ 723,681 $616,848 $ 719,722 $ 595,647 $487,380 $ 671,205 $ 304,549 $ 267,110
Expenses
Product costs, service
and other costs ....... 573,114 487,053 582,934 482,662 405,652 537,792 217,601 199,865
Selling, general and
administrative......... 57,710 51,791 51,157 46,146 43,815 50,024 37,816 33,624
Depreciation and
amortization(2)........ 27,905 23,312 28,693 26,729 26,306 28,039 21,314 20,275
Other expense
(income)............... (215) 132 (347) (69) 2,448 (346) (69) 2,448
---------- -------- --------- --------- -------- ------------ --------- ---------
Operating income......... 65,167 54,560 57,285 40,179 9,159 55,696 27,887 10,898
--------- -------- --------- --------- -------- ------------ --------- ---------
Net interest expense..... (7,541) (4,394) (9,178) (9,260) (10,943) (9,458) (11,504) (12,496)
Other income (expense) 1,028 867 87 89 (534) 88 89 (1,297)
--------- -------- --------- --------- -------- ------------ --------- ---------
Income (loss) before
income taxes........... 58,654 51,033 48,194 31,008 (2,318) 46,326 16,472 (2,895)
Income tax (expense)
benefit(3)............. (14,222) (11,357) (2,090) (4,542) 3,979 (2,054) (10,776) (4,654)
---------- -------- --------- --------- -------- ------------ --------- ---------
Income (loss) from
continuing operations
before minority
interest............... 44,432 39,676 46,104 26,466 1,661 44,272 5,696 (7,549)
Minority interest........ -- -- 4 (30) (31) (1,596) (4,248) 610
--------- -------- --------- --------- -------- ------------ --------- ---------
Income (loss) from
continuing operations.. $ 44,432 $ 39,676 $ 46,108 $ 26,436 $ 1,630 $ 42,676 $ 1,448 $ (6,939)
========= ======== ========= ========= ======== ============ ========= =========
Income (loss) from
continuing operations
before extraordinary
item per common share
Basic.................. $ 0.92 $ 0.82 $ 0.96 $ 0.55 $ 0.03 $ 0.94 $ 0.05 $ (0.30)
========= ======== ========= ========= ======== ============ ========= =========
Diluted................ $ 0.90 $ 0.81 $ 0.95 $ 0.55 $ 0.03 $ 0.93 $ 0.04 $ (0.30)
========= ======== ========= ========= ======== ============ ========= =========
Average shares outstanding
Basic............... 48,529 48,286 48,198 48,013 48,156 45,263 24,482 23,053
========= ======== ========= ========= ======== ============ ========= =========
Diluted................ 49,215 48,890 48,619 48,358 48,529 46,045 26,471 23,069
========= ======== ========= ========= ======== ============ ========= =========
YEAR ENDED DECEMBER 31,
- ------------------------------------------------------------------------------------------------------------------------------------
2001
2003 2002 2001 2000 1999 ------------ 2000 1999
--------- -------- --------- ------- ------- CONSOLIDATED -------- ----------
CONSOLIDATED PRO FORMA (1) AND COMBINED COMBINED
---------------------- --------------------------------- ------------ --------------------
Other Data:
EBITDA as defined(4).... $ 94,100 $ 78,739 $ 86,069 $66,967 $34,900 $ 82,227 $ 45,042 $ 30,486
Capital expenditures.... 41,261 26,086 29,718 29,671 21,383 11,297
Net cash provided by
operating activities.. 58,703 45,375 60,013 54,872 33,937 5,170
Net cash provided by
(used in) investing
activities............ (54,902) (89,428) (27,648) (22,667) (22,377) 112,227
Net cash provided by
(used in) financing
activities............ 4,319 50,381 (34,005) (32,415) 304 (116,122)
21
AT DECEMBER 31,
------------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- --------
CONSOLIDATED COMBINED
------------------------------ --------------------
Balance Sheet Data:
Cash and cash equivalents..................... $ 19,318 $ 11,118 $ 4,982 $ 4,821 $ 3,216
Net property and equipment.................... 194,136 167,146 150,090 143,468 142,242
Total assets.................................. 717,186 644,216 529,883 353,518 355,544
Long-term debt and capital leases,
excluding current portion................... 136,246 133,292 73,939 102,614 120,290
Redeemable preferred stock of
subsidiaries................................ -- -- -- 25,293 25,064
Total stockholders' equity.................... 455,111 387,579 344,197 56,549 58,462
- ----------
(1) The unaudited pro forma statements of operations and other financial
data for 1999, 2000 and 2001 give effect to:
- our initial public offering in February 2001 of 10,000,000
shares at $9.00 per share and the application of the net
proceeds to us;
- our issuance of 4,275,555 shares of common stock to SCF in
exchange for approximately $36.0 million of our indebtedness
held by SCF (SCF Exchange) effected in connection with our
initial public offering;
- the three-for-one reverse stock split of Oil States common
stock effected in connection with our initial public offering;
- the combination of Oil States, HWC and PTI immediately prior
to our initial public offering, excluding the minority
interest of each company, as entities under common control
from the dates such common control was established using
reorganization accounting, which yields results similar to
pooling of interest accounting;
- the acquisition of the minority interests of Oil States, HWC
and PTI in the Combination using the purchase method of
accounting as if the acquisition occurred on January 1, 1999,
2000 and 2001, respectively; and
- the acquisition of Sooner in the Combination using the
purchase method of accounting as if the acquisition occurred
on January 1, 1999, 2000 and 2001, respectively.
(2) In June 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standard ("SFAS") No. 142, "Goodwill and Other
Intangible Assets," which we adopted effective January 1, 2002. Under
SFAS 142, goodwill and intangible assets deemed to have indefinite
lives are no longer amortized but are subject to annual impairment
tests. Accordingly, beginning in 2002, we no longer amortize goodwill.
See "Risks Related to Our Operations -- If we have to write off a
significant amount of goodwill, our earnings will be negatively
affected" in "Item 1. Business" above.
(3) Our effective tax rate is affected by our net operating loss carry
forwards. Our 2003 effective tax rate for financial reporting purposes
was approximately 24%. Although there are a number of factors that
could affect it, we currently estimate that our 2004 effective tax rate
for financial reporting purposes will be approximately 33%. See "Item
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Tax Matters" in this Annual Report on Form
10-K.
(4) The term EBITDA as defined consists of net income plus interest, taxes,
depreciation and amortization. EBITDA as defined is not a measure of
financial performance under generally accepted accounting principles.
You should not consider it in isolation from or as a substitute for net
income or cash flow measures prepared in accordance with generally
accepted accounting principles or as a measure of profitability or
liquidity. Additionally, EBITDA as defined may not be comparable to
other similarly titled measures of other companies. The Company has
included EBITDA as defined as a supplemental disclosure because its
management believes that EBITDA as defined provides useful information
regarding our ability to service debt and to fund capital expenditures
and provides investors a helpful measure for comparing its operating
performance with the
22
performance of other companies that have different financing and
capital structures or tax rates. The Company uses EBITDA as defined to
compare and to monitor the performance of its business segments to
other comparable public companies and as a benchmark for the award of
incentive compensation under our annual incentive compensation plan.
We believe that net income is the financial measure calculated and
presented in accordance with generally accepted accounting principles
that is most directly comparable to EBITDA as defined. The following
table reconciles EBITDA as defined with our net income, as derived from
our financial information:
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------
2001
2003 2002 2001 2000 1999 ------------ 2000 1999
-------- -------- ------- -------- -------- CONSOLIDATED -------- --------
CONSOLIDATED PRO FORMA (1) AND COMBINED COMBINED
------------------- ---------------------------- ------------ -------------------
Net income (loss) from
continuing operations before
extraordinary item............. $ 44,432 $ 39,676 $46,108 $ 26,436 $ 1,630 $ 42,676 $ 1,448 $ (6,939)
Depreciation and
amortization................... 27,905 23,312 28,693 26,729 26,306 28,039 21,314 20,275
Interest expense, net............ 7,541 4,394 9,178 9,260 10,943 9,458 11,504 12,496
Income taxes..................... 14,222 11,357 2,090 4,542 (3,979) 2,054 10,776 4,654
-------- -------- ------- -------- -------- ------------ -------- --------
EBITDA as defined................ $ 94,100 $ 78,739 $86,069 $ 66,967 $ 34,900 $ 82,227 $ 45,042 $ 30,486
======== ======== ======= ======== ======== ============ ======== ========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read the following discussion and analysis together with
"Selected Financial Data" and our financial statements and the notes to those
statements included elsewhere in this Annual Report on Form 10-K.
This discussion contains forward-looking statements based on our
current expectations, assumptions, estimates and projections about us and our
industry. These forward-looking statements involve risks and uncertainties. Our
actual results could differ materially from those indicated in these
forward-looking statements as a result of certain factors, as more fully
described under "Cautionary Statement Regarding Forward-Looking Statements" in
this Form 10-K. Except to the extent required by law, we undertake no obligation
to update publicly any forward-looking statements, even if new information
becomes available or other events occur in the future.
CRITICAL ACCOUNTING POLICIES
In our selection of critical accounting policies, our objective is to
properly reflect our financial position and results of operations in each
reporting period in a manner that will be understood by those who utilize our
financial statements. Often we must use our judgment about uncertainties.
There are several critical accounting policies that we have put into
practice that have an important effect on our reported financial results.
We have contingent liabilities and future claims for which we have made
estimates of the amount of the eventual cost to liquidate these liabilities or
claims. These liabilities and claims sometimes involve threatened or actual
litigation where damages have been quantified and we have made an assessment of
our exposure and recorded a provision in our accounts to cover an expected loss.
Other claims or liabilities have been estimated based on our experience in these
matters and, when appropriate, the advice of outside counsel or other outside
experts. Upon the ultimate resolution of these uncertainties, our future
reported financial results will be impacted by the difference between our
estimates and the actual amounts paid to settle a liability. Examples of areas
where we have made important estimates of future liabilities include litigation,
taxes, postretirement benefits, warranty claims and contract claims.
The determination of impairment on long-lived assets, including
goodwill, is conducted when indicators of impairment are present. If such
indicators were present, the determination of the amount of impairment would be
based on our judgments as to the future operating cash flows to be generated
from these assets throughout their estimated useful lives. Our industry is
highly cyclical and our estimates of the period over which future cash flows
23
will be generated, as well as the predictability of these cash flows, can have a
significant impact on the carrying value of these assets and, in periods of
prolonged down cycles, may result in impairment charges.
We recognize revenue and profit as work progresses on long-term, fixed
price contracts using the percentage-of-completion method, which relies on
estimates of total expected contract revenue and costs. We follow this method
since reasonably dependable estimates of the revenue and costs applicable to
various stages of a contract can be made. Recognized revenues and profit are
subject to revisions as the contract progresses to completion. Revisions in
profit estimates are charged to income or expense in the period in which the
facts and circumstances that give rise to the revision become known. Provisions
for estimated losses on uncompleted contracts are made in the period in which
losses are determined.
Our valuation allowances, especially related to potential bad debts in
accounts receivable and to obsolescence or market value declines of inventory,
involve reviews of underlying details of these assets, known trends in the
marketplace and the application of historical factors that provide us with a
basis for recording these allowances. If market conditions are less favorable
than those projected by management, or if our historical experience is
materially different from future experience, additional allowances may be
required. We record a valuation allowance to reduce our deferred tax assets to
the amount that is more likely than not to be realized. While we have considered
future taxable income and ongoing prudent and feasible tax planning strategies
in assessing the need for the valuation allowance, in the event we were to
determine that we would be able to realize our deferred tax assets in the future
in excess of our net recorded amount, an adjustment to the deferred tax asset
would increase income in the period such determination was made. Likewise,
should we determine that we would not likely be able to realize all or part of
our net deferred tax asset in the future, an adjustment to the deferred tax
asset would be charged to expense in the period such determination was made.
The selection of the useful lives of many of our assets requires the
judgments of our operating personnel as to the length of these useful lives.
Should our estimates be too long or short, we might eventually report a
disproportionate number of losses or gains upon disposition or retirement of our
long-lived assets. We believe our estimates of useful lives are appropriate.
OVERVIEW
We provide a broad range of products and services to the oil and gas
industry through our offshore products, well site services and tubular services
business segments. Demand for our products and services is cyclical and
substantially dependent upon activity levels in the oil and gas industry,
particularly our customers' willingness to spend capital on the exploration for
and development of oil and gas reserves. Demand for our products and services by
our customers is highly sensitive to current and expected oil and natural gas
prices. Our offshore products segment provides highly engineered and technically
designed products for offshore oil and gas development and production systems
and facilities. Sales of our offshore products and services depend upon the
development of offshore production systems, repairs and upgrades of existing
drilling rigs and construction of new drilling rigs. In this segment, we are
particularly influenced by deepwater drilling and production activities. In our
well site services business segment, we provide hydraulic well control services,
pressure control equipment and rental tools, drilling rigs and work force
accommodations, catering and logistics services. Demand for our well site
services depends upon the level of worldwide drilling and workover activity.
Through our tubular services segment, we distribute a broad range of casing and
tubing. Sales of tubular products and services depend upon the overall level of
drilling activity and the types of wells being drilled.
Energy and oilfield service activities are highly cyclical, depending
upon crude oil and natural gas pricing, among other things. Beginning in late
1996 and continuing through the early part of 1998, stabilization of oil and gas
prices led to increases in drilling activity as well as the refurbishment and
new construction of drilling rigs. In the second half of 1998, crude oil prices
declined substantially and reached levels below $11 per barrel in early 1999.
With this decline in pricing, many of our customers substantially reduced their
capital spending and related activities. This industry downturn continued
through most of 1999. The price of crude oil and natural gas increased over 1999
levels in 2000 and 2001 due to improved demand for oil, supply reductions by
OPEC member countries and reductions in natural gas storage levels. Crude oil
and natural gas prices decreased significantly from levels reached in early 2001
by the end of 2001. The economic slowdown in the United States and the rest of
the world, moderate weather and the resultant increased inventories of oil and
gas, especially in the United States, contributed
24
to those price declines. With those price reductions, our customers responded
with decreased drilling activity and spending on exploration and development. In
early 2002, oil and gas prices began to increase and they are currently at
relatively high historic levels.
We have a diversified product and service offering which has exposure
throughout the oil and gas cycle. Demand for our tubular services and well site
services is highly correlated to movements in the rig count in the United
States. The table below sets forth a summary of North American rig activity, as
measured by Baker Hughes Incorporated, as of and for the periods indicated.
AVERAGE RIG COUNT FOR THE YEAR ENDED
RIG COUNT AS OF DECEMBER 31,
JANUARY 31, -----------------------------------------
2004 2003 2002 2001 2000 1999
--------------- ---- ----- ----- ----- ----
US...................... 1,101 1,032 831 1,156 918 624
Canada.................. 554(1) 372 266 341 345 245
----- ----- ----- ----- ----- ----
North America......... 1,655 1,404 1,097 1,497 1,263 869
===== ===== ===== ===== ===== ====
- ----------
(1) Canadian rig counts typically increase during the peak winter drilling
season.
The rig count in the United States and Canada, as measured by Baker
Hughes Incorporated, fell from 1,481 rigs in February 1998 to 559 rigs in April
1999. The downturn in activity in 1998 and 1999 had a material adverse effect on
demand for our products and services, and the results of our operations
decreased significantly. Our business benefited from the improvement in crude
oil and natural gas pricing in 2000 and early 2001 and the resulting increases
in the rig count in 2000 and the first half of 2001. During 2002, the U.S. rig
count decreased in the first half of the year. The U.S. rig count reached its
lowest level since 1999 when it totaled 738 rigs on April 15, 2002. Since then,
the U.S. rig count has risen and totaled 1,404 as of December 31, 2003.
We believe that our offshore products segment lagged the general market
recovery in 2000 and 2001 because its sales primarily relate to offshore
construction and production facility development which generally occur later in
the exploration and development cycle. Worldwide offshore construction and
development activity improved in 2002, and backlog in our offshore products
segment increased to $100.1 million at December 31, 2002, compared to $72.4
million at December 31, 2001. We reported record results for our offshore
product segment in 2002 and 2003 as a result of this increased backlog. Our
backlog has decreased to $62.6 million as of December 31, 2003 reflecting
decreased activity in support of offshore construction and production facility
development. As a result, we expect 2004 activity in the offshore products
segment to result in reduced revenues compared to 2003 with smaller projects and
lower margin work.
Throughout 2003, North American oilfield activity levels, as measured
by rig counts, increased as exploration and production companies spent
additional cash flows resulting from higher oil and gas prices. However, the rig
count increase resulted primarily from shallow land drilling activity while the
U.S. offshore Gulf of Mexico rig count remained relatively flat in 2003. Our
tubular services and well site services businesses results of operations are
impacted by activity levels in the U.S. Gulf of Mexico. The lack of increased
drilling in the U.S. Gulf of Mexico and other more service-oriented areas,
versus the shallow land wells being drilled, has resulted in a lower than
anticipated increase in oil service revenue and profitability in 2003. We expect
strong Canadian and U.S. land drilling activity to continue in 2004. In
addition, contributions from late 2003 and early 2004 acquisitions should
favorably impact results of operations in our well site services segment in
2004.
Management believes that fundamental oil and gas supply and demand
factors will lead to increased drilling activity in North America over time. The
combination of declining U.S. natural gas production, relatively high cash flow
for exploration and production companies, solid demand growth for both oil and
natural gas and expected continued OPEC discipline should lead to continued rise
in oilfield activity levels. However, there can be no assurance that these
expectations will be realized or that increased activity will be in regions that
will benefit our business segments. We view the recent increases in oil and
natural gas prices and reduction in related supplies as important steps toward
increased demand for oilfield service activity.
25
THE COMBINATION
Prior to our initial public offering in February 2001, SCF-III, L.P.
owned majority interests in Oil States, HWC and PTI, and SCF-IV, L.P. owned a
majority interest in Sooner. L. E. Simmons & Associates, Incorporated is the
ultimate general partner of SCF-III, L.P. and SCF-IV, L.P. L.E. Simmons, the
chairman of our board of directors, is the sole shareholder of L.E. Simmons &
Associates, Incorporated. Immediately prior to the closing of our initial public
offering, the Combination closed and HWC, PTI and Sooner merged with wholly
owned subsidiaries of Oil States. As a result, HWC, Sooner and PTI became our
wholly owned subsidiaries.
The financial results of Oil States, HWC and PTI have been combined
from the beginning of calendar 2001 until February 14, 2001 using reorganization
accounting, which yields results similar to the pooling of interests method. The
combined results of Oil States, HWC and PTI form the basis for the discussion of
our results of operations for those periods. The operations of Oil States, HWC
and PTI represent two of our business segments, offshore products and well site
services. Concurrently with the closing of our initial public offering in
February 2001, Oil States acquired Sooner, and the acquisition was accounted for
using the purchase method of accounting. The pro forma financial statement for
the year ended December 31, 2001 reflects the acquisition of Sooner effective as
of January 1, 2001. Following the acquisition of Sooner, we reported under three
business segments.
CONSOLIDATED AND PRO FORMA RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
------- ------- -------
CONSOLIDATED PROFORMA
-------------------- --------
Revenues
Well site services......................... $ 256.1 $ 209.8 $ 239.8
Offshore products.......................... 231.9 190.6 129.3
Tubular services........................... 235.7 216.4 350.6
------- ------- --------
Total..................................... $ 723.7 $ 616.8 $ 719.7
======= ======= ========
Gross Margin
Well site services......................... $ 80.9 $ 63.1 $ 86.2
Offshore products.......................... 56.0 52.9 29.5
Tubular services........................... 13.7 13.8 22.1
Corporate/other............................ -- -- (1.0)
------- ------- --------
Total..................................... $ 150.6 $ 129.8 $ 136.8
======= ======= ========
Gross margin as a percent of revenues
Well site services......................... 31.6% 30.1% 35.9%
Offshore products.......................... 24.1% 27.8% 22.8%
Tubular services........................... 5.8% 6.4% 6.3%
Total..................................... 20.8% 21.0% 19.0%
Operating income (loss)
Well site services......................... $ 37.2 $ 27.4 $ 47.4
Offshore products.......................... 27.9 27.3 6.6
Tubular services........................... 6.0 5.4 12.5
Corporate/other............................ (5.9) (5.5) (9.2)
------- ------- --------
Total..................................... $ 65.2 $ 54.6 $ 57.3
======= ======= ========
YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002
Revenues. Revenues increased $106.9 million, or 17.3%, to $723.7
million during the year ended December 31, 2003 compared to revenues of $616.8
million during the year ended December 31, 2002. Well site services revenues
increased $46.3 million, or 22.1%, and offshore products revenues increased
$41.3 million, or 21.7%, during the same period. Well site services revenues
increased compared to the prior year primarily due to increased drilling
activity in Canada and the United States, favorable Canadian dollar exchange
rates, which strengthened compared to the U.S. dollar in 2003 compared to 2002
resulting in an increase of approximately $14.0 million, and the impact of
acquisitions completed in the third quarter of 2002. Canadian expenses were also
impacted by exchange rate movements in 2003 compared to 2002 and offset some of
these revenue gains. Offshore products revenues increased primarily as a result
of greater activity supporting offshore production facility construction,
primarily in the U.S. Gulf of Mexico, and the impact of acquisitions completed
in the third quarter of 2002. Tubular services revenues increased $19.3 million,
or 8.9%, in the year ended December 31, 2003 compared to the prior year. This
revenue increase resulted from greater quantities shipped caused by higher rig
counts partially offset by lower international sales and reduced revenue per ton
shipped caused by product mix oriented to shallow land drilling.
26
Gross Margin. Our gross margins, which we calculate before a deduction
for depreciation expense, increased $20.8 million, or 16.0%, from $129.8 million
in the year ended December 31, 2002 to $150.6 million in the year ended December
31, 2003.
Well site services gross margins increased $17.8 million, or 28.2%, to
$80.9 million in the year ended December 31, 2003. Within our well site services
segment, shallow drilling and specialty rental tool businesses' gross margins
increased $4.0 million, or 61.9%, and $3.0 million, or 16.2%, respectively,
during the year ended December 31, 2003 compared to the year ended December 31,
2002 primarily as a result of rigs added to the fleet and the rental tool
acquisitions completed. Also in the well site services segment, our work force
accommodations, catering and logistics services and modular building
construction services gross margins increased by $11.1 million, or 37.5%, during
the year ended December 31, 2003 compared to the year ended December 31, 2002
because of increased camp and catering activity in Canada and work supporting
the Canadian military in Afghanistan and Bosnia. Our hydraulic workover gross
margins decreased by $0.3 million, or 2.3%, as a result of decreased activity in
Venezuela and a reclassification of certain field expenses, formerly classified
as selling, general and administrative expenses, to operating expense. These
decreases were almost fully offset by increased gross margin from work in
Algeria, which commenced in late 2002. Gross margin as a percent of revenues in
well site services increased from 30.1% in 2002 to 31.6% in 2003 primarily
because of more profitable accommodations operations caused by higher activity
levels.
Offshore products gross margins increased $3.1 million, or 5.9%, from
$52.9 million in the year ended December 31, 2002 to $56.0 million during 2003
primarily due to increased revenues from shipments and work in progress. Our
offshore products gross margin percentage declined by 3.7% due primarily to a
greater percentage of lower-margin fabrication work compared to the prior period
and to certain project losses incurred in our subsea pipeline operations and to
reduced margins in our winch and crane businesses. Tubular services gross
margins decreased to $13.7 million, or 5.8% of tubular services revenues in the
year ended December 31, 2003 compared to $13.8 million, or 6.4% of tubular
services revenues, in the year ended December 31, 2002 as a result of higher
margin sales during 2002, especially in the fourth quarter, and foreign sales,
which occurred primarily in the first half of 2002, and did not reoccur in 2003.
Selling, General and Administrative Expenses. During the year ended
December 31, 2003, selling, general and administrative expenses (SG&A) totaled
$57.7 million, or 8.0% of revenues, compared to SG&A of $51.8 million, or 8.4%
of revenues, for the year ended December 31, 2002. Increased SG&A expense
primarily resulted from acquisitions completed in the third quarter of 2002.
This increase was only partially offset by lower post employment benefit costs
caused by the settlement of certain plan liabilities during the current year as
explained in Footnote 7 to the Consolidated and Combined Financial Statements
contained in this Annual Report on Form 10-K.
Depreciation and Amortization. Depreciation and amortization expense
increased $4.6 million in 2003 compared to 2002 due primarily to acquisitions of
businesses completed in 2002 and capital expenditures made in 2002 and 2003.
Operating Income. Our operating income represents revenues less (i)
cost of sales, (ii) selling, general and administrative expenses and (iii)
depreciation and amortization expense plus other operating income. Our operating
income increased $10.6 million, or 19.4%, to $65.2 million for the year ended
December 31, 2003 from $54.6 million during 2002. Well site services operating
income increased by $9.8 million, or 35.8%, while offshore products operating
income increased by $0.6 million, or 2.2%. Tubular Services operating income was
$6.0 million during the year ended December 31, 2003 compared to $5.4 million
for the year ended December 31, 2002, an increase of $0.6 million, or 11.1%.
Corporate and other charges increased by $0.4 million in 2003 compared to 2002.
Interest Expense. Interest expense increased $3.0 million, or 61.2%, to
$7.9 million for the year ended December 31, 2003 compared to $4.9 million for
the year ended December 31, 2002. Increased interest expense was attributable to
higher debt levels resulting from acquisitions completed during the third
quarter of 2002, capital expenditures made during 2002 and 2003 and the
write-off of $1.2 million, after taxes, of unamortized debt issue costs in the
fourth quarter of 2003 upon the closing of a new bank credit agreement.
Income Tax Expense. Income tax expense totaled $14.2 million, or 24.2%
of pretax income, during the year ended December 31, 2003 compared to $11.4
million, or 22.3% of pretax income, during the year ended December
27
31, 2002. Decreased amounts of net operating loss carryforwards available to
offset currently taxable income has resulted in a higher annual effective tax
rate for the year 2003 compared to 2002.
YEAR ENDED DECEMBER 31, 2002 COMPARED TO PRO FORMA YEAR ENDED DECEMBER 31, 2001
Revenues. Revenues decreased $102.9 million, or 14.3%, during the year
ended December 31, 2002 to $616.8 million compared to the year ended December
31, 2001. Revenues in our well site services segment decreased $30.0 million, or
12.5%, in the year ended December 31, 2002 compared to the previous year. Within
well site services, comparing the year 2002 to the year 2001, our work force
accommodations, catering and logistics services and modular building
construction services revenues decreased $18.5 million, or 13.6%, due to lower
activity in Canada and the U.S. Gulf of Mexico, our land drilling revenues
decreased $3.1 million, or 10.1%, due to lower activity and drilling rates,
primarily in West Texas, our rental tool services revenues decreased $0.3
million, or 0.8%, because lower activity in our U.S. Gulf of Mexico locations
was partially offset by the impact of acquisitions made by the Company in March
and August 2002 and our workover services revenues decreased $8.1 million, or
21.8%, as activity, especially in the U.S. Gulf of Mexico, decreased compared to
2001. Our offshore products segment revenues increased $61.3 million, or 47.4%,
in the year 2002 compared to the year 2001, due to significantly increased
activity supporting offshore production facility construction, primarily in
deepwater locations. Our tubular services segment revenues in the year 2002 were
$134.2 million, or 38.3%, lower than in the year 2001 because of decreased
drilling activity in the United States and significantly lower foreign sales in
2002 compared to 2001.
Gross Margins. Our gross margins, which we calculate before a deduction
for depreciation and amortization expense, decreased $7.0 million, or 5.1%, to
$129.8 million in the year 2002 compared to the year 2001. Our gross margin as a
percent of revenue improved from 19.0% in the year 2001 to 21.0% in 2002 due to
a more favorable mix of our revenues consisting of higher margin offshore
products and well site services activities with less of our 2002 revenues
consisting of tubular sales. Our offshore products' gross margins increased
$23.4 million, or 79.3%, in the year 2002 compared to the year 2001 and our
gross margin percentage increased to 27.8% in the year 2002 compared to 22.8% in
the year 2001 as higher volumes of product shipments lead to increased operating
efficiencies in the year 2002. Our well site services gross margins decreased
$23.1 million, or 26.8%, to $63.1 million in the year 2002 compared to the year
2001. The gross margin percentage for well site services declined to 30.1% in
the year 2002 compared to 35.9% in 2001. Within our well site services segment,
our land drilling business gross margins decreased $5.1 million, or 44.7%, to
$6.3 million in 2002 compared to total gross margin of $11.4 million in 2001
because of decreased drilling activity and lower prices obtained for drilling
services; our rental tool business reported 2002 gross margins totaling $18.4
million, or 51.5% of revenue, compared to 2001 gross margins totaling $18.9
million, or 52.5% of revenue in 2001 as we saw increased price competition for
rental tools which offset the positive effect of our 2002 rental tool business
acquisitions; our workover services gross margins in the year 2002 totaled $8.7
million, or 30.3% of revenues, compared to 2001 gross margins of $13.4 million,
or 36.1% of revenues, as decreased U.S. Gulf of Mexico margins and activity more
than offset the positive effect of higher international activity; and our work
force accommodations, catering and logistics services and modular building
construction services businesses gross margin decreased in 2002 to $29.6
million, or 25.2% of revenue, compared to $42.4 million, or 31.2% of revenue, in
the previous year because of the impact of lower drilling activity in 2002 in
Canada and the U.S. Gulf of Mexico and because a greater percentage of revenues
resulted from relatively low margin construction activity. Our tubular services
margins in the year 2002 totaled $13.8 million, a decrease of $8.3 million, or
37.6%, compared to the year 2001. While tubular services gross margins were
approximately the same in each of the last two years, the volume of tubular
products shipped in 2002 decreased by approximately 29% compared to 2001.
Selling, General and Administrative Expense. During the year 2002,
selling, general and administrative expenses (SG&A) increased $0.6 million, or
1.2%, to $51.8 million from $51.2 million in the year 2001. As a percent of
revenues, SG&A increased to 8.4% in 2002 compared to 7.1% in 2001. Increased
costs in the year 2002 compared to 2001 at our offshore products segment, driven
by higher activity and increased employee incentive costs were only partially
offset by lower well site services segment costs associated with decreased
activity within that segment.
Depreciation and Amortization. Depreciation and amortization expense
totaled $23.3 million in the year 2002 compared to $28.7 million in 2001. The
$5.4 million decrease is principally related to the elimination of goodwill
amortization in 2002 (in comparison, we amortized $7.5 million of goodwill in
the year 2001) partially offset by
28
additional depreciation and amortization associated with capital additions and
intangibles recorded as part of business acquisitions in the years 2001 and
2002.
Operating Income. Our operating income represents revenues less (i)
cost of sales, (ii) SG&A, and (iii) depreciation and amortization expense plus
other operating income. Our operating income decreased $2.7 million, or 4.7%, to
$54.6 million for 2002 from $57.3 million in 2001. Operating income from our
well site services segment decreased $20.0 million from $47.4 million for 2001
to $27.4 million for 2002. Operating income for our offshore products segment
increased $20.7 million to $27.3 million for 2002 compared to $6.6 million in
2001. Operating income in our tubular services segment decreased $7.1 million
from $12.5 million in 2001 to $5.4 million in 2002. Corporate/other operating
loss improved from a loss of $9.2 million in 2001 to a loss of $5.5 million in
2002 primarily because of the discontinuance of goodwill amortization in 2002.
Net Interest Expense. Net interest expense totaled $4.4 million in the
year 2002, a decrease of $5.1 million, or 53.6%, compared to net interest
expense of $9.5 million in 2001. Both interest rates and average debt balances
were lower during 2002 when compared to 2001. Additionally, a total of $0.8
million of unamortized debt issue costs were expensed in 2001 upon the execution
of a new credit facility.
Income Tax Expense. Our income tax expense totaled $11.4 million, or
22.3% of pretax income, in the year 2002 compared to $2.1 million, or 4.3% of
pretax income in the year 2001. The increased tax expense is primarily due to
the higher effective tax rate which increased in 2002 compared to 2001 as a
result of a lower amount of net operating loss carryforwards available to offset
taxable income.
LIQUIDITY AND CAPITAL RESOURCES
Our primary liquidity needs are to fund capital expenditures, such as
expanding and upgrading our manufacturing facilities and equipment, increasing
and replacing our drilling rig, rental tool and workover assets and our
accommodation units, funding new product development and funding general working
capital needs. In addition, capital is needed to fund strategic business
acquisitions. Our primary sources of funds have been cash flow from operations
and proceeds from borrowings under our bank facilities.
Cash was provided by operations during the years ended December 31,
2003 and 2002 in the amounts of $58.7 million and $45.4 million, respectively.
Cash provided by operations in 2003 was generated by our net income plus
depreciation and amortization which was partially offset by working capital
invested in 2003 in our offshore products and tubular services businesses.
Cash was used in investing activities during the years ended December
31, 2003 and 2002 in the amounts of $54.9 million and $89.4 million,
respectively. Capital expenditures totaled $41.3 million and $26.1 million
during the years ended December 31, 2003 and 2002, respectively. Capital
expenditures in 2003 and 2002 consisted principally of purchases of assets for
our well site services businesses and for expansion of our offshore products
manufacturing capacity. We completed acquisitions for cash consideration
totaling $16.3 million and $64.8 million, respectively, during the years ended
December 31, 2003 and 2002. We currently expect to spend a total of
approximately $35.0 million during 2004 to upgrade our equipment and facilities
and expand our product and service offerings. We expect to fund these capital
expenditures with internally generated funds and proceeds from borrowings under
our revolving credit facilities. In January 2004, the Company completed the
acquisition of several related rental tool companies for cash consideration of
$34.7 million. This acquisition was funded by the Company's revolving credit
facility. See Note 18 to the Consolidated and Combined financial statements
contained in this Annual Report on Form 10K.
Net cash of $4.3 million was provided from financing activities during
the year ended December 31, 2003, primarily as a result of revolving credit
borrowings and proceeds from stock option exercises.
As of December 31, 2003, we had $128.7 million outstanding under our
primary bank credit facility and an additional $10.3 million of outstanding
letters of credit, leaving $86.0 million available to be drawn under the
facility. Our total debt represented 23.2% of our total capitalization at
December 31, 2003.
29
The following summarizes our debt and lease obligations at December 31,
2003 (in thousands):
DUE IN LESS DUE IN DUE IN DUE AFTER
DECEMBER 31, 2003 TOTAL THAN 1 YEAR 1-3 YEARS 3 - 5 YEARS 5 YEARS
----------------- --------- ------------ --------- ----------- ---------
Debt and lease obligations:
Long-term debt, including capital
leases............................. $ 137,119 $ 873 $ 3,954 $ 130,338 $ 1,954
Non-cancelable operating leases...... 11,607 3,769 3,960 1,200 2,678
--------- ------------ -------- ---------- ---------
Total contractual cash obligations... $ 148,726 $ 4,642 $ 7,914 $ 131,538 $ 4,632
========= ============ ======== =========== =========
Our debt obligations at December 31, 2003 are included in our
consolidated balance sheet, which is a part of our consolidated financial
statements included in this Annual Report on Form 10-K. We have not entered into
any material leases subsequent to December 31, 2003. We do not have any off
balance sheet arrangements.
In October 2003, we entered into a new $225 million senior secured
revolving credit facility with a group of banks. Up to $45.0 million of
commitments under the credit facility are available in the form of loans
denominated in Canadian dollars and may be made to our principal Canadian
operating subsidiaries. This credit facility replaced the existing facility and
matures on October 30, 2007, unless extended for an additional one year period
with the consent of the lenders. The Company has the option to expand the
facility to $250 million. Amounts borrowed under this facility bear interest, at
our election, at either:
- a variable rate equal to LIBOR (or, in the case of Canadian
dollar denominated loans, the Bankers' Acceptance discount
rate) plus a margin ranging from 1.5% to 2.5%; or
- an alternate base rate equal to the higher of the bank's prime
rate and the federal funds effective rate plus 0.5% (or, in
the case of Canadian dollar denominated loans, the Canadian
Prime Rate) plus a margin ranging from 0.5% to 1.5%, depending
upon the ratio of total debt to EBITDA (as defined in the
credit facility).
We pay commitment fees ranging from 0.375% to 0.5% per year on the
undrawn portion of the facility, depending upon our leverage ratio. Our weighted
average interest rate on the Company's outstanding borrowings under this
facility at December 31, 2003 was 3.6%.
Our credit facility is guaranteed by all of our active domestic
subsidiaries and, in some cases, our Canadian and other foreign subsidiaries.
Our credit facility is secured by a first priority lien on all our inventory,
accounts receivable and other material tangible and intangible assets, as well
as those of our active subsidiaries. However, no more than 65% of the voting
stock of any foreign subsidiary is required to be pledged if the pledge of any
greater percentage would result in adverse tax consequences.
Our ability to borrow under the facility is subject to certain
customary conditions, including the continuing accuracy of representations and
warranties, the lack of material adverse changes, our continuing compliance with
laws and the lack of defaults under the facility.
Our credit facility contains negative covenants that restrict our
ability to borrow additional funds, encumber assets, pay dividends, sell assets
except in the normal course of business and enter into other significant
transactions.
In addition, our credit facility requires us to maintain:
- a ratio of EBITDA, less maintenance capital expenditures, to
interest expense and certain current maturities of debt of not
less than 2.5 to 1.0;
- a level of consolidated net worth of not less than $370
million, plus 50% of each quarter's consolidated net income
(but not loss) and 75% of equity offerings;
- a maximum ratio of total debt to EBITDA of not greater than
3.0 to 1.0.
Under our credit facility, the occurrence of specified change of
control events involving our company would constitute an event of default that
would permit the banks to, among other things, accelerate the maturity of the
facility and cause it to become immediately due and payable in full.
30
We had an aggregate of approximately $8.4 million of subordinated debt
and capital leases outstanding at December 31, 2003. The subordinated debt will
become due and payable at various times through September 2007. See Note 6 to
our Consolidated and Combined Financial Statements included in this Annual
Report on Form 10-K.
We believe that cash from operations and available borrowings under our
credit facility will be sufficient to meet our liquidity needs for the
foreseeable future. If our plans or assumptions change or are inaccurate, or we
make significant acquisitions, individually or in the aggregate, we may need to
raise additional capital. However, there is no assurance that we will be able to
raise additional funds or be able to raise such funds on favorable terms.
TAX MATTERS
For the year ended December 31, 2003, we had deferred tax liabilities,
net of deferred tax assets, of approximately $4.3 million for federal income tax
purposes before application of valuation allowances. Our primary deferred tax
assets are net operating loss carry forwards, or NOLs, which total approximately
$63 million. A valuation allowance is currently provided against the majority of
our NOLs. The NOLs expire over a period through 2020. Our NOLs are currently
limited under Section 382 of the Internal Revenue Code due to a change of
control that occurred during 1995. In 2004, approximately $31 million of NOLs
are available for use if sufficient income is generated. A successive change in
control was triggered in 2003 pursuant to Section 382; however it did not
significantly lessen the amount of NOLs available.
Our 2003 effective tax rate was approximately 24%. This low effective
tax rate was due to the partial utilization of net operating losses which
benefited the consolidated group after the Combination. During 2003, we paid
cash taxes of $12.9 million.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued
Statements of Financial Accounting Standards (SFAS) No. 141, "Business
Combinations," and No. 142, "Goodwill and Other Intangible Assets" (the
"Statements"), effective for fiscal years beginning after December 15, 2001.
Under the new rules, goodwill and intangible assets deemed to have indefinite
lives will no longer be amortized but will be subject to annual impairment tests
in accordance with the Statements. Other intangible assets will continue to be
amortized over their useful lives.
We began applying the new rules on accounting for goodwill and other
intangible assets in the first quarter of 2002. Application of the
nonamortization provisions of the Statements resulted in an increase in net
income of approximately $8.0 million ($.16 per diluted share) for year 2002. We
have performed the required impairment tests of goodwill and indefinite lived
intangible assets as of December 31, 2002 and 2003 and there was no impairment
of assets indicated.
In June 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." We were required to adopt
this Statement effective January 1, 2003, and it did not have an impact on our
consolidated financial statements.
In August 2001, the Financial Accounting Standards Board issued SFAS
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." We
were required to adopt this Statement effective January 1, 2002, and it did not
have an impact on our consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No.
145 which, among other things, rescinded SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt." We adopted this statement in 2003, and as a
result, classified as interest expense a $1.2 million non-cash write-off, after
taxes, of unamortized
31
debt issue costs resulting from a new financing completed in October 2003. We
reclassified $0.8 million of losses incurred in 2001 on debt restructuring,
formerly classified as an extraordinary loss, to interest expense.
We have adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure," issued
in December 2002, effective with our December 31, 2002 consolidated and combined
financial statements and related footnotes.
In January 2003, the Financial Accounting Standards Board (FASB) issued
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities, an interpretation of ARB No. 51." FIN 46 provides guidance on: 1) the
identification of entities for which control is achieved through means other
than through voting rights, known as "variable interest entities" (VIEs); and 2)
which business enterprise is the primary beneficiary and when it should
consolidate a VIE. This new requirement for consolidation applies to entities:
1) where the equity investors (if any) do not have a controlling financial
interest; or 2) whose equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial support
from other parties. In addition, FIN 46 requires that both the primary
beneficiary and all other enterprises with a significant variable interest in a
VIE make additional disclosures. FIN 46 is effective for all new VIEs created or
acquired after January 31, 2003. For VIEs created or acquired prior to February
1, 2003, the provisions of FIN 46 must be applied for the first interim or
annual period ending after December 15, 2003. Certain disclosures are effective
immediately. Implementation of FIN 46 did not affect the Company.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk. We have long-term debt and revolving lines of
credit subject to the risk of loss associated with movements in interest rates.
As of December 31, 2003, we had floating rate obligations totaling
approximately $128.7 million for amounts borrowed under our revolving credit
facility. These floating-rate obligations expose us to the risk of increased
interest expense in the event of increases in short-term interest rates. If the
floating interest rate were to increase by 1% from December 31, 2003 levels, our
consolidated interest expense would increase by a total of approximately $1.3
million annually.
Foreign Currency Exchange Rate Risk. Our operations are conducted in
various countries around the world in a number of different currencies. As such,
our earnings are subject to movements in foreign currency exchange rates when
transactions are denominated in currencies other than the U.S. dollar, which is
our functional currency. In order to mitigate the effects of exchange rate
risks, we generally pay a portion of our expenses in local currencies and a
substantial portion of our contracts provide for collections from customers in
U.S. dollars. As of December 31, 2003, we had a foreign currency forward
purchase option contract totaling $5.0 million which served as a cash flow hedge
for our UK operations. We have incurred no material gains or losses from foreign
currency hedging activities.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our combined, pro forma combined and consolidated financial statements
and supplementary data of the Company appear on pages 41 through 74 of this
Annual Report on Form 10-K and are incorporated by reference into this Item 8.
Selected quarterly financial data is set forth in Note 16 to our Consolidated
and Combined Financial Statements, which is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There were no changes in or disagreements on any matters of accounting
principles or financial statement disclosure between us and our independent
auditors during our two most recent fiscal years or any subsequent interim
period.
32
ITEM 9A. CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer performed an
evaluation of our disclosure controls and procedures, which have been designed
to permit us to effectively identify and timely disclose important information.
They concluded that the controls and procedures were effective as of December
31, 2003 to ensure that material information was accumulated and communicated to
the Company's management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure. During the three-months ended December 31, 2003 we have made no
changes in our internal controls over financial reporting or in other factors
that could significantly affect our internal controls over financial reporting.
Pursuant to section 906 of The Sarbanes-Oxley Act of 2002, our Chief
Executive Officer and Chief Financial Officer have provided certain
certifications to the Securities and Exchange Commission. These certifications
accompanied this report when filed with the Commission, but are not set forth
herein.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(1) Information concerning directors, including the Company's
audit committee financial expert, appears in the Company's
Definitive Proxy Statement, under "Election of Directors."
This portion of the Definitive Proxy Statement is incorporated
herein by reference.
(2) Information with respect to executive officers appears in the
Company's Definitive Proxy Statement, under "Executive
Officers of the Registrant." This portion of the Definitive
Proxy Statement is incorporated herein by reference.
(3) Information concerning Section 16(a) beneficial ownership
reporting compliance appears in the Company's Definitive Proxy
Statement, under "Section 16(a) Beneficial Ownership Reporting
Compliance." This portion of the Definitive Proxy Statement is
incorporated herein by reference.
The Company has adopted the Corporate Code of Business Conduct and
Ethics, a code of ethics with which every director and employee of the Company
is expected to comply. The Corporate Code of Business Conduct and Ethics is
publicly available on the Company's website under Investors Relations at
www.oilstatesintl.com and is available in print to any stockholder who requests
it. If any substantive amendments are made to the Corporate Code of Business
Conduct and Ethics or if there is a grant of a waiver, including any implicit
waiver, from a provision of the code to the Company's Chief Executive Officer,
Chief Financial Officer or Chief Accounting Officer or Controller, the Company
will disclose the nature of such amendment or waiver on the Company's website or
in a report on Form 8-K.
The Company has also adopted Corporate Governance Guidelines, a set of
guidelines by which the Company and its officers and directors are expected to
govern the affairs of the Company. The Corporate Governance Guidelines, as well
as the charter of the Company's audit, compensation and nominating and corporate
governance committees, are available on the Company's website and in print to
any stockholder who requests them. This website address is intended to be an
inactive, textual reference only. None of the material on this website is
incorporated by reference into this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 hereby is incorporated by reference
to such information as set forth in the Company's Definitive Proxy Statement for
the 2004 Annual Meeting of Stockholders.
33
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The table below provides information relating to our equity
compensation plans as of December 31, 2003:
NUMBER OF SECURITIES
REMAINING AVAILABLE FOR
NUMBER OF SECURITIES TO WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER
BE ISSUED UPON EXERCISE EXERCISE PRICE OF COMPENSATION PLANS
OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, (EXCLUDING SECURITIES
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS REFLECTED IN FIRST COLUMN)
- ------------------------- ----------------------- -------------------- -------------------------
Equity compensation plans
approved by security
holders.................. 2,680,743 $ 9.78 2,014,044
Equity compensation plans
not approved by
security holders......... N/A N/A N/A
--------- ------ ---------
Total 2,680,743 $ 9.78 2,014,044
========= ====== =========
We do not have any equity compensation plans not approved by our
stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 hereby is incorporated by reference
to such information as set forth in the Company's Definitive Proxy Statement for
the 2004 Annual Meeting of Stockholders.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accountant fees and services and the
audit committee's preapproval policies and procedures appear in the Company's
Definitive Proxy Statement under the heading "Fees Paid to Ernst & Young LLP"
and is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Index to Financial Statements, Financial Statement Schedules
and Exhibits
(1) Financial Statements: Reference is made to the index
set forth on page 41 of this Annual Report on Form 10-K.
(2) Financial Statement Schedules: No schedules have been
included herein because the information required to be submitted has
been included in the Consolidated and Combined Financial Statements or
the Notes thereto, or the required information is inapplicable.
(3) Index of Exhibits: See Index of Exhibits, below, for
a list of those exhibits filed herewith, which index also includes and
identifies management contracts or compensatory plans or arrangements
required to be filed as exhibits to this Annual Report on Form 10-K by
Item 601(10)(iii) of Regulation S-K.
(b) Reports on Form 8-K.
(1) Form 8-K dated October 28, 2003 - Item 12. Results of
Operations and Financial Condition (Quarter ended
September 30, 2003 Earnings Press Release)
(2) Form 8-K dated November 3, 2003 - Item 5. Other
Events (New Credit Agreement).
(c) Index of Exhibits
EXHIBIT NO. DESCRIPTION
- ---------- -----------
3.1 -- Amended and Restated Certificate of Incorporation
(incorporated by reference to Exhibit 3.1 to the Company's
Annual Report on Form 10-K for the year ended December 31,
2000, as filed with the Commission on March 30, 2001).
34
3.2 -- Amended and Restated Bylaws (incorporated by reference to
Exhibit 3.2 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2000, as filed with the
Commission on March 30, 2001).
3.3 -- Certificate of Designations of Special Preferred Voting
Stock of Oil States International, Inc. (incorporated by
reference to Exhibit 3.3 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, as filed
with the Commission on March 30, 2001).
4.1 -- Form of common stock certificate (incorporated by reference
to Exhibit 4.1 to the Company's Registration Statement on
Form S-1 (File No. 333-43400)).
4.2 -- Amended and Restated Registration Rights Agreement
(incorporated by reference to Exhibit 4.2 to the Company's
Annual Report on Form 10-K for the year ended December 31,
2000, as filed with the Commission on March 30, 2001).
4.3 -- First Amendment to the Amended and Restated Registration
Rights Agreement dated May 17, 2002 (incorporated by
reference to Exhibit 4.3 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2002, as filed
with the Commission on March 13, 2003).
10.1 -- Combination Agreement dated as of July 31, 2000 by and among
Oil States International, Inc., HWC Energy Services, Inc.,
Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc.
and PTI Group Inc. (incorporated by reference to Exhibit
10.1 to the Company's Registration Statement on Form S-1
(File No. 333-43400)).
10.2 -- Plan of Arrangement of PTI Group Inc. (incorporated by
reference to Exhibit 10.2 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, as filed
with the Commission on March 30, 2001).
10.3 -- Support Agreement between Oil States International, Inc. and
PTI Holdco (incorporated by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 2000, as filed with the Commission on March 30,
2001).
10.4 -- Voting and Exchange Trust Agreement by and among Oil States
International, Inc., PTI Holdco and Montreal Trust Company
of Canada (incorporated by reference to Exhibit 10.4 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 2000, as filed with the Commission on March 30,
2001).
10.5** -- 2001 Equity Participation Plan (incorporated by reference to
Exhibit 10.5 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2000, as filed with the
Commission on March 30, 2001).
10.6* -- Deferred Compensation Plan effective November 1, 2003.
10.7** -- Annual Incentive Compensation Plan (incorporated by
reference to Exhibit 10.7 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, as filed
with the Commission on March 30, 2001).
10.8** -- Executive Agreement between Oil States International, Inc.
and Douglas E. Swanson (incorporated by reference to Exhibit
10.8 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission
on March 30, 2001).
10.9** -- Executive Agreement between Oil States International, Inc.
and Cindy B. Taylor (incorporated by Reference to Exhibit
10.9 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission
on March 30, 2001).
35
10.10** -- Form of Executive Agreement between Oil States
International, Inc. and Named Executive Officer (Mr. Hughes)
(incorporated by reference to Exhibit 10.10 of the Company's
Registration Statement on Form S-1 (File No. 333-43400)).
10.11** -- Form of Change of Control Severance Plan for Selected
Members of Management (incorporated by reference to Exhibit
10.11 of the Company's Registration Statement on Form S-1
(File No. 333-43400)).
10.12 -- Credit Agreement, dated as of October 30, 2003, among Oil
States International, Inc., the Lenders named therein and
Wells Fargo Bank Texas, National Association, as
Administrative Agent and U.S. Collateral Agent; and Bank of
Nova Scotia, as Canadian Administrative Agent and Canadian
Collateral Agent; Hibernia National Bank and Royal Bank of
Canada, as Co-Syndication Agents and Bank One, NA and Credit
Lyonnais New York Branch, as Co-Documentation Agents
(incorporated by reference to Exhibit 10.12 to the Company's
Quarterly Report on Form 10Q for the three months ended
September 30, 2003, as filed with the Commission on November
11, 2003.)
10.13A** -- Restricted Stock Agreement, dated February 8, 2001, between
Oil States International, Inc. and Douglas E. Swanson
(incorporated by reference to Exhibit 10.13A to the
Company's Quarterly Report on Form 10-Q for the three months
ended March 31, 2002, as filed with the Commission on May
15, 2001).
10.13B** -- Restricted Stock Agreement, dated February 22, 2001, between
Oil States International, Inc. and Douglas E. Swanson
(incorporated by reference to Exhibit 10.13B to the
Company's Quarterly Report on Form 10-Q for the three months
ended March 31, 2002, as filed with the Commission on May
15, 2001).
10.14** -- Form of Indemnification Agreement (incorporated by reference
to Exhibit 10.14 of the Company's Registration Statement on
Form S-1 (File No. 333-43400)).
10.15** -- Form of Executive Agreement between Oil States
International, Inc. and named Executive Officer (Mr. Slator)
(incorporated by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December 31,
2001, as filed with the Commission on March 1, 2002).
10.16** -- Douglas E. Swanson contingent option award dated as of
February 11, 2002 (incorporated by reference to Exhibit
10.17 to the Company's Quarterly Report on Form 10-Q for the
three months ended September 30, 2002 as filed with the
Commission on November 13, 2002).
10.17** -- Form of Executive Agreement between Oil States
International, Inc. and named executive officer (Mr. Trahan)
(incorporated by reference to Exhibit 10.16 to the Company's
Quarterly Report on Form 10-Q for the three months ended
June 30, 2002, as filed with the Commission on August 13,
2002).
21.1* -- List of subsidiaries of the Company.
23.1* -- Consent of Ernst & Young LLP
24.1* -- Powers of Attorney for Directors
31.1* -- Certification of Chief Executive Officer of Oil States
International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934.
31.2* -- Certification of Chief Financial Officer of Oil States
International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934.
32.1*** -- Certification of Chief Executive Officer of Oil States
International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b)
under the Securities Exchange Act of 1934.
32.2*** -- Certification of Chief Financial Officer of Oil States
International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b)
under the Securities Exchange Act of 1934.
36
---------
* Filed herewith
** Management contracts or compensatory plans or arrangements
*** Furnished herewith.
37
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
OIL STATES INTERNATIONAL, INC.
By /s/ DOUGLAS E. SWANSON
----------------------------
Douglas E. Swanson
President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed by the following persons on behalf of the registrant
in the capacities indicated on March 5, 2004.
SIGNATURE TITLE
--------- -----
L.E. SIMMONS* Chairman of the Board
- -------------------------------------------------------
L.E. Simmons
/s/ DOUGLAS E. SWANSON Director, President and Chief Executive Officer
- ------------------------------------------------------- (Principal Executive Officer)
Douglas E. Swanson
/s/ CINDY B. TAYLOR Senior Vice President, Chief Financial Officer
- ------------------------------------------------------- and Treasurer
Cindy B. Taylor (Principal Financial Officer)
/s/ ROBERT W. HAMPTON Vice President -- Finance and Accounting and Secretary
- ------------------------------------------------------- (Principal Accounting Officer)
Robert W. Hampton
MARTIN LAMBERT* Director
- -------------------------------------------------------
Martin Lambert
MARK G. PAPA* Director
- -------------------------------------------------------
Mark G. Papa
GARY L. ROSENTHAL* Director
- -------------------------------------------------------
Gary L. Rosenthal
ANDREW L. WAITE* Director
- -------------------------------------------------------
Andrew L. Waite
STEPHEN A. WELLS* Director
- -------------------------------------------------------
Stephen A. Wells
*By: /s/ CINDY B. TAYLOR
--------------------------------------------------
Cindy B. Taylor, pursuant to a power of
attorney filed as Exhibit 24.1 to this
Annual Report on Form 10-K
38
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
INDEX TO COMBINED, PRO FORMA COMBINED AND
CONSOLIDATED FINANCIAL STATEMENTS
Unaudited Pro Forma Consolidated and Combined Financial
Statement...................................................... 40
Unaudited Pro Forma Consolidated and Combined Statement of
Operations for the Year Ended December 31, 2001................ 41
Notes to Unaudited Pro Forma Consolidated and Combined
Financial Statement............................................ 42
Consolidated and Combined Financial Statements
Reports of Independent Auditors Ernst and Young LLP............... 44
Consolidated and Combined Statements of Income for the Years
Ended December 31, 2003, 2002, and 2001........................ 45
Consolidated Balance Sheets at December 31, 2003 and 2002......... 46
Consolidated and Combined Statements of Stockholders'
Equity and Comprehensive Income (Loss) for the Years Ended
December 31, 2003, 2002 and 2001............................... 47
Consolidated and Combined Statements of Cash Flow for the
Years Ended December 31, 2003, 2002, and 2001.................. 48
Notes to the Consolidated and Combined Financial
Statements..................................................... 49
39
UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENT
The consolidated financial statements of Oil States International, Inc.
reflect the Company's financial position, results of operations and changes in
stockholders' equity for periods subsequent to February 14, 2001, the date of
the Company's initial public offering and the combination of Oil States
International, Inc. (Oil States), HWC Energy Services, Inc. (HWC) and PTI Group
Inc. (PTI) (collectively the Controlled Group), among other things.
As more fully described below, and in footnotes that follow, the
combined financial statements reflect the financial position, results of
operations and changes in stockholders' equity of the predecessor entities that
now comprise Oil States International, Inc. based on reorganization accounting.
The pro forma financial information that follows reflect the Company's
historical consolidated or combined statements of operations, depending upon the
period involved, and give effect to the pro forma transactions and adjustments
more fully described below.
The following tables set forth unaudited pro forma consolidated and
combined financial information for Oil States giving effect to:
- the combination of Oil States, HWC and PTI as entities under
the common control of SCF-III L.P. (SCF III), based upon
reorganization accounting, which yields results similar to
pooling of interest accounting, effective from the dates each
of these entities became controlled by SCF III;
- the conversion of the common stock held by the minority
interests of each entity in the Controlled Group into shares
of the Company's common stock, based on the purchase method of
accounting;
- the conversion of all of the outstanding common stock of
Sooner Inc. (Sooner) into shares of the Company's common
stock, based on the purchase method of accounting; and
- the exchange of 4,275,555 shares of common stock for $36.0
million of debt of Sooner and Oil States; and
- the Company's sale of 10,000,000 shares of common stock (the
Offering) and the application of the net proceeds totaling
$84.1 million. With the proceeds received in the Offering, the
Company repaid $43.7 million of outstanding subordinated debt
of the Controlled Group and Sooner, redeemed $21.8 million of
preferred stock of Oil States, paid accrued interest on
subordinated debt and accrued dividends on preferred stock
aggregating $7.1 million, and repurchased common stock from
non-accredited shareholders and shareholders holding
pre-emptive stock purchase rights for $1.6 million. The
balance of the proceeds was used to reduce amounts outstanding
under bank lines of credit.
The unaudited pro forma consolidated and combined statement of operations for
the years ended December 31, 2001 was prepared based upon the historical
consolidated and combined financial statements of the Controlled Group, adjusted
to conform accounting policies, and give effect to:
- the Company's acquisition of minority interests of the
Controlled Group;
- the Company's acquisition of Sooner;
- the Company's exchange of shares of common stock for debt of
Sooner and Oil States; and
- the Company's sale of shares in the Offering,
as if these transactions had occurred on January 1, 2001.
The unaudited pro forma combined financial statement does not purport
to be indicative of the results that would have been obtained had the
transactions described above been completed on the indicated date or that may be
obtained in the future. The unaudited pro forma combined financial statement
should be read in conjunction with the historical consolidated and combined
financial statements and notes thereto included elsewhere in this Annual Report
on Form 10-K.
40
OIL STATES INTERNATIONAL, INC.
PRO FORMA CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001
HISTORICAL PRO FORMA
---------------------------- -------------------------------------------------------------
CONSOLIDATED PRO FORMA
AND SOONER INC. CONSOLIDATED
COMBINED (PERIOD MINORITY AND COMBINED
YEAR ENDED FROM SOONER INC. INTEREST OFFERING YEAR ENDED
DECEMBER 31, 01/01/01 TO ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS DECEMBER 31,
2001 02/14/01) (NOTE 2) (NOTE 3) (NOTES 1, 3 AND 4) 2001
------------- ----------- ----------- ----------- ------------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Revenue.......................... $ 671,205 $ 48,517 $ $ $ $719,722
Expenses
Costs of sales................. 537,792 45,142 582,934
Selling, general and
administrative.............. 50,024 1,133 51,157
Depreciation and amortization.. 28,039 188 331 135 28,693
Other income................... (346) (1) (347)
--------- -------- ------ ------ ------- --------
Operating income (loss).......... 55,696 2,055 (331) (135) 57,285
--------- -------- ------ ------ ------- --------
Interest income.................. 602 22 624
Interest expense................. (10,060) (585) 843(A) (9,802)
Other income..................... 88 (1) 87
--------- -------- ------ ------ ------- --------
Earnings (loss) before income
taxes....................... 46,326 1,491 (331) (135) 843 48,194
Income tax (expense) benefit..... (2,054) (542) 506(C) (2,090)
--------- -------- ------ ------ ------- --------
Net income (loss) before minority
interests...................... 44,272 949 (331) (135) 1,349 46,104
Minority interests............... (1,596) -- 1,600 4
--------- -------- ------ ------ ------- --------
Net income (loss) ............... 42,676 949 (331) (135) 2,949 46,108
Preferred stock dividends........ (41) -- 41(B) --
--------- -------- ------ ------ ------- --------
Net income attributable to common
shares......................... $ 42,635 $ 949 $ (331) $ (135) $ 2,990 $ 46,108
========= ======== ====== ====== ======= ========
Net income per common share
Basic.......................... $ 0.94 $ 0.96
Diluted........................ $ 0.93 $ 0.95
Average shares outstanding
Basic.......................... 45,263 48,198
Diluted........................ 46,045 48,619
41
OIL STATES INTERNATIONAL, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED AND
COMBINED FINANCIAL STATEMENT
BASIS OF PRESENTATION
The purchase method of accounting has been used to reflect the
acquisition of the minority interests of each company in the Controlled Group
concurrent with the closing of the Offering. The purchase price is based on the
fair value of the shares owned by the minority interests, valued at the initial
public offering price of $9.00 per share. Under this accounting method, the
excess of the purchase price over the fair value of the assets and liabilities
allocable to the minority interests acquired has been reflected as goodwill.
Where book value of minority interests exceeded the purchase price, such excess
reduced property, plant and equipment. For purposes of the pro forma combined
financial statement, the goodwill recorded in connection with this transaction
was initially being amortized over 20 years using the straight-line method based
on management's evaluation of the nature and duration of customer relationships
and considering competitive and technological developments in the industry.
Note, however, that accounting for goodwill changed under new accounting
pronouncements (See Note 3 to Consolidated and Combined Financial Statements).
The unaudited pro forma statement of operations for the year ended December 31,
2001 has been adjusted for the effects of purchase accounting, as described
below.
The purchase method of accounting was also used to reflect the
acquisition of the outstanding common stock of Sooner concurrent with the
closing of the Offering. The purchase price is based on the fair value of the
shares of Sooner, valued at the initial public offering price of $9.00 per
share. The excess of the purchase price over the fair value of the assets and
liabilities of Sooner has been reflected as goodwill. For purposes of the pro
forma combined financial statement, the goodwill recorded in connection with
this transaction was initially being amortized over 15 years using the
straight-line method based on management's evaluation of the nature and duration
of customer relationships and considering competitive and technological
developments in the industry. Note, however, that accounting for goodwill
changed under new accounting pronouncements (See Note 3 to Consolidated and
Combined Financial Statements). The unaudited pro forma statement of operations
for the year ended December 31, 2001 includes the historical financial
statements of Sooner, converted to a calendar year end and adjusted for the
effects of purchase accounting, as presented below.
NOTE 1. COMBINING ADJUSTMENTS
Minority interest in (income) loss and related tax effect of the
Controlled Group are presented below (in thousands):
OIL STATES HWC PTI TOTAL
---------- --- --- -----
Period from January 1, 2001 to February
14, 2001............................... $ 72 $ (129) $ (1,543) $ (1,600)
====== ====== ======== ========
NOTE 2. ACQUISITION OF SOONER
Certain reclassifications have been made to conform the presentation of
Sooner's financial statements to the Controlled Group.
To reflect the acquisition of all outstanding common shares of Sooner
in exchange for 7,597,152 shares of Oil States common stock valued at the
estimated offering price per share of $9.00 (in millions):
Purchase price.................................................................. $ 69.5(1)
Less: fair value of net assets acquired......................................... 29.7
-------
Goodwill........................................................................ $ 39.8
-------
Amortization for the period from January 1, 2001 to February 14, 2001....... $ .33
=======
- -----------------
(1) The purchase price for Sooner includes the estimated fair value of Sooner
stock options ($1.1 million) converted into Oil States stock options.
42
NOTE 3. ACQUISITION OF MINORITY INTERESTS
To reflect the acquisition of the minority interests of each company in
the Controlled Group in exchange for shares of Oil States common stock and
elimination of the historical amounts reflected for the combined group (in
millions, except share and per share information):
OIL STATES HWC PTI COMBINED
----------- ---------- ----------- -----------
Common stock issued to minority
interests..................... 1,418,729 1,359,603 4,204,058 6,982,390
Offering price per share........ $ 9.00 $ 9.00 $ 9.00 $ 9.00
----------- ---------- ----------- -----------
Purchase price of the minority
interests..................... 12.8 12.2 37.8 62.8
Minority interests in fair
value of net assets acquired.. 13.8 7.7 15.9 37.4
----------- ---------- ----------- -----------
Additional goodwill............. $ (1.0) $ 4.5 $ 21.9 $ 25.4
=========== ========== =========== ===========
Amortization of the additional
goodwill for the period from
January 1, 2001 to February
14, 2001...................... $ (.015) $ .020 $ .130 $ .135
=========== ========== =========== ===========
NOTE 4. OFFERING
(A) To adjust interest expense for debt repaid with Offering proceeds
and as a result of the exchange of shares for subordinated debt.
(B) To eliminate preferred stock dividends due to the redemption of the
preferred stock.
(C) To adjust income tax expense for the reduction of deferred taxes
due to the formation of the combined group.
43
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT AUDITORS
THE BOARD OF DIRECTORS AND STOCKHOLDERS OF OIL STATES INTERNATIONAL, INC.
We have audited the accompanying consolidated balance sheets of Oil States
International, Inc. and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of income, stockholders' equity and
comprehensive income (loss), and cash flows for each of the two years in the
period ended December 31, 2003 and the related consolidated and combined
statements of income, stockholders' equity and comprehensive income (loss) and
cash flows for the year ended December 31, 2001. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Oil States
International, Inc. and subsidiaries at December 31, 2003 and 2002, and the
consolidated results of their operations and their cash flows for each of the
two years in the period ended December 31, 2003 and the consolidated and
combined results of their operations and their cash flows for the year ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 3 to the consolidated and combined financial statements,
effective January 1, 2002, the Company adopted Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets."
ERNST & YOUNG LLP
Houston, Texas
February 2, 2004
44
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
-----------------------------------------
2003 2002 2001
--------- --------- ------------
CONSOLIDATED
CONSOLIDATED AND COMBINED
------------------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues:
Product........................................... $ 442,238 $ 391,067 $421,758
Service and other................................. 281,443 225,781 249,447
--------- --------- --------
723,681 616,848 671,205
Costs and expenses:
Product costs..................................... 379,854 331,380 376,260
Service and other costs........................... 193,260 155,673 161,532
Selling, general and administrative expenses...... 57,710 51,791 50,024
Depreciation expense.............................. 26,736 22,825 20,790
Amortization expense.............................. 1,169 487 7,249
Other operating expense (income).................. (215) 132 (346)
---------- --------- --------
658,514 562,288 615,509
--------- --------- --------
Operating income.................................... 65,167 54,560 55,696
Interest expense.................................... (7,930) (4,863) (10,060)
Interest income..................................... 389 469 602
Other income........................................ 1,028 867 88
--------- --------- --------
Income before income taxes and minority interest.... 58,654 51,033 46,326
Income tax provision................................ (14,222) (11,357) (2,054)
Minority interest in income of combined companies
and consolidated subsidiaries..................... -- -- (1,596)
--------- --------- --------
Net income.......................................... 44,432 39,676 42,676
Preferred stock dividends........................... -- -- (41)
--------- --------- --------
Net income attributable to common shares............ $ 44,432 $ 39,676 $ 42,635
========= ========= ========
Basic net income per share.......................... $ 0.92 $ 0.82 $ 0.94
Diluted net income per share........................ $ 0.90 $ 0.81 $ 0.93
Weighted average number of common shares outstanding
(in thousands):
Basic............................................. 48,529 48,286 45,263
Diluted........................................... 49,215 48,890 46,045
The accompanying notes are an integral part of these financial statements.
45
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
---------------------
2003 2002
--------- --------
(IN THOUSANDS, EXCEPT
SHARE AMOUNTS)
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 19,318 $ 11,118
Accounts receivable, net................................... 137,484 116,875
Inventories, net........................................... 121,319 118,338
Prepaid expenses and other current assets.................. 9,956 9,475
--------- --------
Total current assets..................................... 288,077 255,806
Property, plant and equipment, net........................... 194,136 167,146
Goodwill, net................................................ 224,054 213,051
Other noncurrent assets...................................... 10,919 8,213
--------- --------
Total assets............................................. $ 717,186 $644,216
========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities................... $ 89,243 $ 84,049
Income taxes............................................... 3,020 1,229
Current portion of long-term debt.......................... 873 913
Deferred revenue........................................... 4,784 8,949
Other current liabilities.................................. 937 1,402
--------- --------
Total current liabilities................................ 98,857 96,542
Long-term debt............................................. 136,246 133,292
Deferred income taxes...................................... 19,411 18,303
Postretirement healthcare benefits......................... 2,662 5,280
Other liabilities.......................................... 4,899 3,220
--------- --------
Total liabilities........................................ 262,075 256,637
Stockholders' equity:
Common stock, $.01 par value, 200,000,000 shares
authorized, 49,161,599 shares and 48,523,158 shares
issued and outstanding, respectively..................... 492 485
Additional paid-in capital................................. 333,855 327,801
Retained earnings.......................................... 108,818 64,386
Less:
Common stock held in treasury at cost,-- 33,423 and 18,078
shares, respectively..................................... (343) (172)
Accumulated other comprehensive income (loss).............. 12,289 (4,921)
--------- --------
Total stockholders' equity............................... 455,111 387,579
--------- --------
Total liabilities and stockholders' equity............... $ 717,186 $644,216
========= ========
The accompanying notes are an integral part of these financial statements.
46
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME (LOSS)
ACCUMULATED
OTHER
ADDITIONAL RETAINED COMPREHENSIVE
PREFERRED COMMON PAID-IN EARNINGS COMPREHENSIVE INCOME TREASURY
STOCK STOCK CAPITAL (DEFICIT) INCOME (LOSS) STOCK
--------- --------- ---------- --------------------------- -------------- ---------
(IN THOUSANDS)
BALANCE, DECEMBER 31, 2000......... $ 1,625 $ 272 $ 83,810 $ (25,854) $ (3,304) $ --
Net income....................... 42,676 $ 42,676
Currency translation adjustment (3,723) (3,723)
---------
Comprehensive income............. $ 38,953
=========
Issuance of common stock for cash 100 79,615
Amortization of restricted stock
compensation................... 1 421
Preferred stock dividends........ (41)
Redeemable preferred stock
dividends...................... (285)
Redemption of preferred stock.... (1,625)
Conversion of preferred stock to
common stock................... 5,143
Conversion of debt to common
stock.......................... 43 35,936
Shares issued to acquire Sooner.. 76 30,596
Shares issued to acquire minority
interest.................... 174 92,329 7,929
Purchase of subsidiary stock in
connection with Combination.... (2) (1,465)
Three-for-one reverse stock split (181) 181
Other............................ (250)
------- ------- --------- ---------- ----------- ---------
BALANCE, DECEMBER 31, 2001......... -- 483 326,031 24,710 (7,027) --
Net income....................... 39,676 $ 39,676
Currency translation adjustment 2,106 2,106
---------
Comprehensive income............. $ 41,782
=========
Exercise of stock options,
including tax benefit.......... 2 1,619
Amortization of restricted stock
compensation................... 378
Stock acquired in deferred
compensation plan.............. (172)
Other............................ (227)
------- ------- --------- ---------- ----------- ---------
BALANCE, DECEMBER 31, 2002......... -- 485 327,801 64,386 (4,921) (172)
Net income....................... 44,432 $ 44,432
Currency translation adjustment 17,210 17,210
---------
Comprehensive income............. $ 61,642
=========
Exercise of stock options,
including tax benefit.......... 7 5, 842
Stock issuance costs............. (338)
Amortization of restricted stock
compensation................... 450
Stock acquired in deferred
compensation plan.............. (171)
Other............................ 100
-------- ------- --------- ---------- ----------- ---------
BALANCE, DECEMBER 31, 2003......... $ -- $ 492 $ 333,855 $ 108,818 $ 12,289 $ (343)
======== ======= ========= ========== =========== =========
The accompanying notes are an integral part of these financial statements.
47
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
--------- --------- ---------
(IN THOUSANDS)
Cash flows from operating activities:
Net income........................................ $ 44,432 $ 39,676 $ 42,676
Adjustments to reconcile net income to net cash
provided by operating activities:
Minority interest, net of distributions......... -- (44) 1,596
Depreciation and amortization................... 27,905 23,312 28,039
Deferred income tax provision (benefit)......... 714 4,897 (11,504)
Provision for loss on accounts receivable....... 702 130 1,571
Deferred financing cost amortization............ 2,303 1,110 1,456
Gain on disposal of assets...................... (492) (142) (225)
Gain on sale of other businesses................ -- -- (227)
Equity in earnings of unconsolidated subsidiary. (355) (632) (76)
Other, net...................................... 913 883 454
Changes in operating assets and liabilities, net
of effect from acquired and divested businesses:
Accounts receivable............................. (12,880) 10,576 (20,030)
Inventories..................................... 194 (29,273) 28,758
Accounts payable and accrued liabilities........ 96 (1,836) (16,057)
Taxes payable................................... 988 (3,111) (605)
Other current assets and liabilities, net....... (5,817) (171) (954)
--------- --------- ---------
Net cash flows provided by operating activities. 58,703 45,375 54,872
Cash flows from investing activities:
Acquisitions of businesses, net of cash acquired.. (16,286) (64,847) (5,119)
Capital expenditures.............................. (41,261) (26,086) (29,671)
Proceeds from sale of equipment................... 2,671 1,432 5,976
Cash acquired in Sooner acquisition............... -- -- 4,894
Proceeds from sale of other businesses............ -- -- 1,200
Other, net........................................ (26) 73 53
--------- --------- ---------
Net cash flows used in investing activities..... (54,902) (89,428) (22,667)
Cash flows from financing activities:
Revolving credit borrowings (repayments).......... 4,209 54,786 (10,132)
Debt borrowings................................... -- 20 --
Debt and capital lease repayments................. (1,757) (4,070) (76,628)
Preferred stock dividends......................... -- -- (844)
Issuance of common stock.......................... 4,177 1,205 84,599
Repurchase of preferred stock..................... -- -- (21,775)
Payment of offering and financing costs........... (2,310) (1,560) (4,982)
Other, net........................................ -- -- (2,653)
--------- --------- ---------
Net cash flows provided by (used in) financing
activities...................................... 4,319 50,381 (32,415)
Effect of exchange rate changes on cash and cash
equivalents...................................... 1,101 111 (4)
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents from continuing operations........... 9,221 6,439 (214)
Net cash provided by (used in) discontinued
operations....................................... (1,021) (303) 375
Cash and cash equivalents, beginning of year....... 11,118 4,982 4,821
--------- --------- ---------
Cash and cash equivalents, end of year............. $ 19,318 $ 11,118 $ 4,982
========= ========= =========
The accompanying notes are an integral part of these financial statements.
48
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
The consolidated financial statements include the accounts of Oil
States International, Inc. (Oil States or the Company) and its consolidated
subsidiaries since February 14, 2001. On February 14, 2001, the Company acquired
the three companies (HWC Energy Services, Inc. -- HWC; PTI Group, Inc. -- PTI
and Sooner Inc. -- Sooner) reported in the Combined financial statements
presented herein. The combined financial statements include the activities of
Oil States, HWC and PTI, (collectively, the Controlled Group) for the period
prior to February 14, 2001, utilizing reorganization accounting. The
reorganization accounting method, which yields results similar to the pooling of
interests method, has been used in the preparation of the combined financial
statements of the Controlled Group (entities under common control of SCF-III
L.P. (SCF-III), a private equity fund that focuses on investments in the energy
industry). Under this method of accounting, the historical financial statements
of HWC and PTI are combined with Oil States for the period until February 14,
2001 when Oil States, HWC and PTI merged and Oil States acquired Sooner in
exchange for its common stock. After February 14, 2001, the consolidated
financial statements of Oil States include the results of all its subsidiaries
including HWC, PTI and Sooner. The combined financial statements have been
adjusted to reflect minority interests in the Controlled Group. All significant
intercompany accounts and transactions between the entities have been eliminated
in the accompanying consolidated and combined financial statements.
OIL STATES INDUSTRIES, INC.
Oil States Industries, Inc. (OSI), a subsidiary of Oil States, is a
leading designer and manufacturer of a diverse range of products for offshore
platforms, subsea pipelines, and defense and general industrial applications.
Major product lines include flexible bearings, advanced connectors, winches,
mooring and lifting systems, services for installing and removing offshore
platforms, downhole production equipment, and custom molded products. Sales are
made primarily to major oil companies, large and small independent oil and gas
companies, drilling contractors, and well service and workover operators on a
worldwide basis. OSI has facilities in Arlington, Houston and Lampasas, Texas;
Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil; England and Singapore.
PTI GROUP, INC.
PTI is located in Alberta, Canada and is a supplier of integrated
housing, food, site management and logistics support services to remote sites
utilized by natural resources and other industries primarily in Canada and the
United States.
HWC ENERGY SERVICES, INC.
HWC provides worldwide well control services, drilling services and
rental equipment to the oil and gas industry. HWC operates primarily in Texas,
Louisiana, Ohio, Oklahoma, New Mexico and Wyoming, along with foreign operations
conducted in Venezuela, the Middle East, and Africa. Its hydraulic well control
operations provide, globally, hydraulic workover (snubbing) units for emergency
well control situations and, in selected markets, various hydraulic well control
solutions involving well drilling and workover and completion activities. In
West Texas and Ohio, HWC operates, through its subsidiary Capstar Drilling,
L.P., shallow well drilling rigs with automated pipe handling capabilities.
Specialty Rental Tools and Supply, L.P., a subsidiary of HWC, provides rental
equipment for drilling and workover operations in Texas, Louisiana, Mississippi,
New Mexico, Oklahoma and Wyoming.
SOONER, INC.
Sooner is a distributor of oilfield tubular products with operations
located primarily in the United States. The majority of sales are to large fully
integrated and independent oil companies headquartered in the U.S.
49
2. INITIAL PUBLIC OFFERING, MERGER TRANSACTIONS AND REFINANCING
On February 9, 2001, the Company's common stock began trading on the
New York Stock Exchange under the symbol "OIS" pursuant to completion of its
initial public offering (the Offering). On February 14, 2001, the Company closed
the business combination and the Offering thereby acquiring the minority
interests in PTI and HWC and 100% of the Sooner operations. The Company recorded
additional goodwill of $61.9 million as a result of the acquisition of these
minority interests.
Concurrently with the Offering, the Company acquired Sooner for $69.5
million. The Company exchanged 7,597,152 shares of its common stock for all the
outstanding common shares of Sooner. The Company accounted for the acquisition
using the purchase method of accounting and recorded approximately $40 million
in goodwill.
Concurrently with the closing of the Offering, the Company issued
4,275,555 shares of common stock to SCF-III and SCF-IV L.P. (SCF-IV) in exchange
for approximately $36.0 million of indebtedness of Oil States and Sooner which
was held by SCF-III and SCF-IV (the SCF Exchange).
With the proceeds received in the Offering, the Company repaid $43.7
million of outstanding subordinated debt of the Controlled Group and Sooner,
redeemed $21.8 million of preferred stock of Oil States, paid accrued interest
on subordinated debt and accrued dividends on preferred stock aggregating $7.1
million, and repurchased common stock from non-accredited shareholders and
shareholders holding pre-emptive stock purchase rights for $1.6 million. The
balance of the proceeds was used to reduce amounts outstanding under bank lines
of credit.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash
equivalents, investments, receivables, payables, and debt instruments. The
Company believes that the carrying values of these instruments on the
accompanying consolidated balance sheets approximate their fair values.
INVENTORIES
Inventories consist of tubular and other oilfield products,
manufactured equipment, and spare parts for manufactured equipment. Inventories
include raw materials, labor, and manufacturing overhead. The cost of tubular
goods inventories is determined using the first-in, first-out (FIFO) method and
the cost for the remaining inventories is determined on an average cost or
specific-identification method.
PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment are stated at cost, or at estimated fair
market value at acquisition date if acquired in a business combination, and
depreciation is computed using the straight-line method over the estimated
useful lives of the assets. Leasehold improvements are capitalized and amortized
over the lesser of the life of the lease or the estimated useful life of the
asset.
Expenditures for repairs and maintenance are charged to expense when
incurred. Expenditures for major renewals and betterments, which extend the
useful lives of existing equipment, are capitalized and depreciated. Upon
retirement or disposition of property and equipment, the cost and related
accumulated depreciation are removed from the accounts and any resulting gain or
loss is recognized in the statements of income.
50
GOODWILL
Goodwill represents the excess of the purchase price for acquired
businesses over the allocated value of the related net assets. Prior to 2002,
goodwill was amortized on a straight-line basis over a period of 15 to 40 years
based on management's evaluation of the nature and duration of customer
relationships and considering competitive and technological developments in the
industry. Goodwill is stated net of accumulated amortization of $18.0 million
and $17.4 million at December 31, 2003 and 2002, respectively. The amount of
accumulated amortization of goodwill increased in 2003 compared to 2002 because
of changes in foreign currency exchange rates. In 2001, the Financial Accounting
Standards Board issued a new standard that affected goodwill amortization (See
"Recent Accounting Pronouncements" below).
IMPAIRMENT OF LONG-LIVED ASSETS
In compliance with Statement of Financial Accounting Standards (SFAS)
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" the
recoverability of the carrying values of property, plant and equipment is
assessed at a minimum annually, or whenever, in management's judgment, events or
changes in circumstances indicate that the carrying value of such assets may not
be recoverable based on estimated future cash flows. If this assessment
indicates that the carrying values will not be recoverable, as determined based
on undiscounted cash flows over the remaining useful lives, an impairment loss
is recognized. The impairment loss equals the excess of the carrying value over
the fair value of the asset. The fair value of the asset is based on prices of
similar assets, if available, or discounted cash flows. Based on the Company's
review, the carrying value of its assets are recoverable and no impairment
losses have been recorded for the periods presented.
FOREIGN CURRENCY AND OTHER COMPREHENSIVE INCOME
Gains and losses resulting from balance sheet translation of foreign
operations where a foreign currency is the functional currency are included as a
separate component of accumulated other comprehensive income within
stockholders' equity. Gains and losses resulting from balance sheet translation
of foreign operations where the U.S. dollar is the functional currency are
included in the consolidated statements of income as incurred.
FOREIGN EXCHANGE RISK
A portion of revenues, earnings and net investments in foreign
affiliates are exposed to changes in foreign exchange rates. We seek to manage
our foreign exchange risk in part through operational means, including managing
expected local currency revenues in relation to local currency costs and local
currency assets in relation to local currency liabilities. Foreign exchange risk
is also managed through the use of derivative financial instruments and foreign
currency denominated debt. These financial instruments serve to protect net
income against the impact of the translation into U.S. dollars of certain
foreign exchange denominated transactions. At December 31, 2003 and 2002, the
financial instruments employed to manage foreign exchange risk consisted of
forward exchange contracts with notional amounts of $5 million at each year-end.
Net gains or losses from foreign currency exchange contracts that are designated
as hedges are recognized in the income statement to offset the foreign currency
gain or loss on the underlying transaction. Exchange gains and losses have not
been material to the results of operations of the Company.
REVENUE AND COST RECOGNITION
Revenue from the sale of products, not accounted for utilizing the
percentage of completion method, is recognized upon shipment to the customer or
when all significant risks of ownership have passed to the customer. For
significant fabrication projects built to customer specifications, revenues are
recognized under the percentage-of-completion method, measured by the percentage
of costs incurred to date to estimated total costs for each contract
(cost-to-cost method). Billings on such contracts in excess of costs incurred
and estimated profits are classified as deferred revenue. Management believes
this method is the most appropriate measure of progress on large fabrication
contracts. Provisions for estimated losses on uncompleted contracts are made in
the period in which such losses are determined. In rental equipment and
services, revenues are recognized based on a periodic (usually daily) rental
rate or when the services are rendered. Proceeds from customers for the cost of
oilfield rental equipment that is damaged
51
or lost downhole are reflected as revenues. For drilling contracts based on
footage drilled, we recognize revenues as footage is drilled.
Cost of goods sold includes all direct material and labor costs and
those costs related to contract performance, such as indirect labor, supplies,
tools, and repairs. Selling, general, and administrative costs are charged to
expense as incurred.
INCOME TAXES
The Company follows the liability method of accounting for income taxes
in accordance with SFAS No. 109, "Accounting for Income Taxes." Under this
method, deferred income taxes are recorded based upon the differences between
the financial reporting and tax bases of assets and liabilities and are measured
using the enacted tax rates and laws that will be in effect when the underlying
assets or liabilities are recovered or settled.
When the Company's earnings from foreign subsidiaries are considered to
be indefinitely reinvested, no provision for U.S. income taxes is made for these
earnings. If any of the subsidiaries have a distribution of earnings in the form
of dividends or otherwise, the Company would be subject to both U.S. income
taxes (subject to an adjustment for foreign tax credits) and withholding taxes
payable to the various foreign countries.
In accordance with SFAS No. 109, the Company records a valuation
reserve in each reporting period when management believes that it is more likely
than not that any deferred tax asset created will not be realized. Management
will continue to evaluate the appropriateness of the reserve in the future based
upon the operating results of the Company.
RECEIVABLES AND CONCENTRATION OF CREDIT RISK
Based on the nature of its customer base, the Company does not believe
that it has any significant concentrations of credit risk other than its
concentration in the oil and gas industry. The Company evaluates the
credit-worthiness of its major new and existing customers' financial condition
and, generally, the Company does not require significant collateral from its
domestic customers.
ALLOWANCES FOR DOUBTFUL ACCOUNTS
The Company maintains allowances for doubtful accounts for estimated
losses resulting from the inability of the Company's customers to make required
payments. If a trade receivable is deemed to be uncollectible, such receivable
is charged-off against the allowance for doubtful accounts. The Company
considers the following factors when determining if collection of revenue is
reasonably assured: customer credit-worthiness, past transaction history with
the customer, current economic industry trends and changes in customer payment
terms. If the Company has no previous experience with the customer, the Company
typically obtains reports from various credit organizations to ensure that the
customer has a history of paying its creditors. The Company may also request
financial information, including financial statements or other documents to
ensure that the customer has the means of making payment. If these factors do
not indicate collection is reasonably assured, the Company would require a
prepayment or other arrangement to support revenue recognition and recording of
a trade receivable. If the financial condition of the Company's customers were
to deteriorate, adversely affecting their ability to make payments, additional
allowances would be required.
EARNINGS PER SHARE
The Company's basic income (loss) per share (EPS) amounts have been
computed based on the average number of common shares outstanding, including
340,971 and 824,546 shares of common stock as of December 31, 2003 and 2002,
respectively, issuable upon exercise of exchangeable shares of one of the
Company's Canadian subsidiaries. These exchangeable shares, which were issued to
certain former shareholders of PTI in connection with the Company's IPO and the
combination of PTI into the Company, are intended to have characteristics
essentially equivalent to the Company's common stock prior to the exchange. We
have treated the shares of common stock issuable upon exchange of the
exchangeable shares as outstanding. Diluted EPS amounts include the effect of
the Company's outstanding stock options under the treasury stock method and the
effect of convertible preferred stock
52
in periods when such preferred shares were outstanding. All shares awarded under
the Company's Equity Participation Plan are included in the Company's fully
diluted shares.
STOCK-BASED COMPENSATION
The Company accounts for its stock-based compensation plans under the
principles prescribed by the Accounting Principles Board's Opinion No. 25 ("APB
No. 25"), "Accounting for Stock Issued to Employees." Stock options awarded
under the Equity Participation Plan normally do not result in recognition of
compensation expense. However, 100,000 shares of restricted stock awarded under
the Equity Participation Plan in February 2001 are considered to be compensatory
in nature. Accordingly, the Company recognized $0.3 million of non-cash general
and administrative expenses for that award in each of the three years ended
December 31, 2003. An additional $0.1 million was recognized in 2003 for a stock
option performance award. The Company accounts for assets held in a rabbi trust
for certain participants under the Company's deferred compensation plan in
accordance with EITF 97-14. See Note 14.
GUARANTEES
The Company adopted FASB Interpretation No. 45 (FIN 45), "Guarantor's
Accounting and Disclosure Requirements for Guarantees, including Indirect
Indebtedness of Other," during 2003. FIN 45 requires disclosures and accounting
for the Company's obligations under certain guarantees.
Pursuant to FIN 45, the Company is required to disclose the changes in
product warranty reserves. Some of our products in our offshore products and
accommodations businesses are sold with a warranty, generally between 12 to 18
months. Parts and labor are covered under the terms of the warranty agreement.
The warranty provision is based on historical experience by product,
configuration and geographic region.
Changes in the warranty reserves were as follows (in thousands):
YEAR ENDED DECEMBER 31,
--------------------------
2003 2002
--------- -----------
Beginning balance................ $ 845 $ 1,341
Provisions for warranty.......... 1,159 588
Consumption of reserves.......... (912) (1,075)
Translation and other changes.... 43 (9)
--------- -----------
Ending balance................... $ 1,135 $ 845
========= ===========
As noted above, certain of our products are sold with a 12 to 18 month
warranty. Accordingly, current warranty provisions are related to the current
year's sales, and warranty consumption is associated with current and prior
year's net sales.
During the ordinary course of business, the Company also provides
standby letters of credit or other guarantee instruments to certain parties as
required for certain transactions initiated by either the Company or its
subsidiaries. As of December 31, 2003, the maximum potential amount of future
payments that the Company could be required to make under these guarantee
agreements was approximately $10.3 million. The Company has not recorded any
liability in connection with these guarantee arrangements beyond that required
to appropriately account for the underlying transaction being guaranteed. The
Company does not believe, based on historical experience and information
currently available, that it is probable that any amounts will be required to be
paid under these guarantee arrangements.
RECLASSIFICATIONS
Certain amounts in prior years' financial statements have been
reclassified to conform with the current year presentation.
53
USE OF ESTIMATES
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires the use
of estimates and assumptions by management in determining the reported amounts
of assets and liabilities and disclosures of contingent assets and liabilities
at the date of the consolidated financial statements and the reported amounts of
revenues and expenses during the reporting period. Examples of a few such
estimates include the costs associated with the disposal of discontinued
operations, including potential future adjustments as a result of contractual
agreements, revenue and income recognized on the percentage-of-completion
method, the valuation allowance recorded on net deferred tax assets and warranty
and bad debt reserves. Actual results could differ from those estimates.
4. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
Additional information regarding selected balance sheet accounts at
December 31, 2003 and 2002, is presented below (in thousands):
2003 2002
--------- ---------
Accounts receivable:
Trade......................................... $ 113,003 $ 101,314
Unbilled revenue.............................. 24,018 14,788
Other......................................... 2,484 3,060
Allowance for doubtful accounts............... (2,021) (2,287)
--------- ---------
$ 137,484 $ 116,875
========= =========
2003 2002
--------- ---------
Inventories:
Tubular goods................................. $ 65,026 $ 60,816
Other finished goods and purchased products... 26,286 22,339
Work in process............................... 20,117 25,678
Raw materials................................. 15,169 14,283
--------- ---------
Total inventories.......................... 126,598 123,116
Inventory reserves............................ (5,279) (4,778)
--------- ---------
$ 121,319 $ 118,338
========= =========
ESTIMATED
USEFUL LIFE 2003 2002
----------- --------- ---------
Property, plant and equipment:
Land............................. $ 5,264 $ 4,675
Buildings and leasehold
improvements..................... 2-40 years 43,784 34,348
Machinery and equipment.......... 2-20 years 198,677 166,702
Rental tools..................... 3-10 years 40,960 32,323
Office furniture and equipment... 1-10 years 14,676 12,710
Vehicles......................... 2-5 years 8,521 6,817
Construction in progress......... 5,712 1,791
--------- ---------
Total property, plant and
equipment........................ 317,594 259,366
Less: Accumulated depreciation... (123,458) (92,220)
--------- ---------
$ 194,136 $ 167,146
========= =========
2003 2002
--------- ---------
Accounts payable and accrued liabilities:
Trade accounts payable........................ $ 59,423 $ 52,212
Accrued compensation.......................... 12,572 13,674
Accrued insurance............................. 3,518 3,870
Accrued taxes, other than income taxes........ 2,028 2,020
Reserves related to discontinued operations,
current portion............................. 4,785 5,216
Other......................................... 6,917 7,057
--------- ---------
$ 89,243 $ 84,049
========= =========
54
5. RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill
and Other Intangible Assets" (SFAS No. 142). In connection with the adoption of
SFAS No. 142, the Company ceased amortizing goodwill. Under SFAS No. 142,
goodwill is no longer amortized but is tested for impairment using a fair value
approach, at the "reporting unit" level. A reporting unit is the operating
segment, or a business one level below that operating segment (the "component"
level) if discrete financial information is prepared and regularly reviewed by
management at the component level. We recognize an impairment charge for any
amount by which the carrying amount of a reporting unit's goodwill exceeds its
fair value. The Company uses comparative market multiples to establish fair
values.
The Company amortizes the cost of other intangibles over their
estimated useful lives unless such lives are deemed indefinite. Amortizable
intangible assets are tested for impairment based on undiscounted cash flows
and, if impaired, written down to fair value based on either discounted cash
flows or appraised values. Intangible assets with indefinite lives are tested
for impairment and written down to fair value as required. No provision for
goodwill or other intangibles impairment was required based on the evaluations
performed.
Changes in the carrying amount of goodwill for the year ended December
31, 2002 and 2003, are as follows (in thousands):
OFFSHORE WELLSITE TUBULAR
PRODUCTS SERVICES SERVICES TOTAL
-------- -------- -------- ---------
Balance as of January 1, 2002.... $ 41,585 $ 81,156 $ 49,494 $ 172,235
Goodwill acquired................ 29,489 10,591 -- 40,080
Foreign currency translation and
other changes.................. 515 136 85 736
-------- -------- -------- ---------
Balance as of December 31, 2002.. 71,589 91,883 49,579 213,051
Goodwill acquired................ 2,622 3,910 -- 6,532
Foreign currency translation and
other changes.................. 589 3,882 4,471
-------- -------- -------- ---------
Balance as of December 31, 2003.. $ 74,800 $ 99,675 $ 49,579 $ 224,054
======== ======== ======== =========
The following table presents what reported income available to common
stockholders and net income per share would have been in all periods presented
exclusive of amortization expense recognized in those periods related to
goodwill (in thousands, except per share amounts):
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
------- -------- ------------
CONSOLIDATED
CONSOLIDATED AND COMBINED
------------------- ------------
Reported net income after preferred dividends $44,432 $ 39,676 $ 42,635
Add: Goodwill amortization................... -- -- 6,920
------- -------- --------
Adjusted net income.......................... $44,432 $ 39,676 $ 49,555
======= ======== ========
Basic earnings per share:
Reported net income after preferred dividends $ 0.92 $ 0.82 $ 0.94
Goodwill amortization........................ -- -- 0.15
------- -------- --------
Adjusted net income.......................... $ 0.92 $ 0.82 $ 1.09
======= ======== ========
Diluted earnings per share:
Reported net income after preferred dividends $ 0.90 $ 0.81 $ 0.93
Goodwill amortization........................ -- -- 0.15
------- -------- --------
Adjusted net income.......................... $ 0.90 $ 0.81 $ 1.08
======= ======== ========
The following table presents the total amount assigned and the total
amount amortized for major intangible asset classes as of December 31, 2003 and
2002 (in thousands):
DECEMBER 31, 2003 DECEMBER 31, 2002
---------------------------- ----------------------------
GROSS CARRYING ACCUMULATED GROSS CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------------- ------------ -------------- ------------
Amortizable intangible assets
Non-compete agreements.......... $ 6,375 $ 1,554 $ 3,979 $ 508
Other........................... 1,210 161 1,160 59
---------- ---------- ------------ ---------
$ 7,585 $ 1,715 $ 5,139 $ 567
========== ========== ============ =========
55
The weighted average remaining amortization period for all intangible
assets is 4.4 years and 5.8 years as of December 31, 2003 and 2002,
respectively. Total amortization expense is expected to be $1.6 million, $1.4
million and $1.3 million in 2004, 2005 and 2006, respectively.
In April 2002, the Financial Accounting Standards Board issued SFAS No.
145 which, among other things, rescinded SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt". The Company adopted this statement in 2003, and,
in conjunction with executing a new revolving credit facility on October 30,
2003, the Company recognized additional non-cash interest expense of $1.2
million, after taxes, for the write-off of deferred financing costs related to
its prior credit facility. We reclassified $0.8 million of losses incurred in
2001 on debt restructuring, formerly classified as an extraordinary loss, to
interest expense.
The Company has adopted the disclosure requirements of SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure," issued
in December 2002, effective with its December 31, 2002 consolidated and combined
financial statements and related footnotes.
In January 2003, the Financial Accounting Standards Board (FASB) issued
FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities, an interpretation of ARB No. 51." FIN 46 provides guidance on: 1) the
identification of entities for which control is achieved through means other
than through voting rights, known as "variable interest entities" (VIEs); and 2)
which business enterprise is the primary beneficiary and when it should
consolidate a VIE. This new requirement for consolidation applies to entities:
1) where the equity investors (if any) do not have a controlling financial
interest; or 2) whose equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial support
from other parties. In addition, FIN 46 requires that both the primary
beneficiary and all other enterprises with a significant variable interest in a
VIE make additional disclosures. FIN 46 is effective for all new VIEs created or
acquired after January 31, 2003. For VIEs created or acquired prior to February
1, 2003, the provisions of FIN 46 must be applied for the first interim or
annual period ending after December 15, 2003. Certain disclosures are effective
immediately. Implementation of FIN 46 did not affect the Company.
6. LONG-TERM DEBT
As of December 31, 2003 and 2002, long-term debt consisted of the
following (in thousands):
2003 2002
---------- ----------
US revolving credit facility, with available commitments
of up to $180 million; secured by substantially all assets;
commitment fee on unused portion ranged from 0.375% to 0.5%
per annum in 2003 and 2002; variable interest rate payable
monthly based on prime or LIBOR plus applicable percentage;
weighted average rate was 3.52% for 2003 and 3.62% for
2002....................................................... $ 128,700 $ 121,100
Canadian revolving credit facility, with available
commitments of up to $45 million; secured by substantially
all assets; variable interest rate payable monthly based
on the Canadian prime rate or Bankers Acceptance discount
rate plus applicable percentage; weighted average rate was
5.5% for 2003 and 6.0% for 2002............................ -- 3,165
Subordinated notes payable due November 30, 2005; interest
accrues at 7.00% annually; principal and interest are
payable at a fixed amount for each day the acquired
equipment is utilized...................................... 3,497 3,840
Subordinated unsecured notes payable due September 26, 2007;
interest accrues at 5% and is payable at maturity.......... 1,092 1,918
Obligations under capital leases............................ 3,818 4,158
Other notes payable in monthly installments of principal
and interest at various interest rates..................... 12 24
---------- ----------
Total debt............................................. 137,119 134,205
Less: current maturities.................................... 873 913
---------- ----------
Total long-term debt................................... $ 136,246 $ 133,292
========== ==========
56
Scheduled maturities of combined long-term debt as of December 31,
2003, are as follows (in thousands):
YEAR ENDING DECEMBER 31,
- --------------------------
2004...................... $ 873
2005...................... 3,616
2006...................... 338
2007...................... 130,066
2008 ..................... 272
Thereafter................ 1,954
---------
$ 137,119
=========
The Company's capital leases consist primarily of plant facilities and
equipment. Capitalized lease assets value and related accumulated depreciation
totaled $4.3 million and $1.5 million at December 31, 2003, respectively.
Capitalized lease assets value and related accumulated depreciation totaled $4.2
million and $1.1 million at December 31, 2002, respectively.
CURRENT DEBT INSTRUMENTS
On October 30, 2003, the Company replaced its existing credit facility
with a $225.0 million senior secured revolving credit facility with a group of
banks. Up to $45.0 million of the credit facility is available in the form of
loans denominated in Canadian dollars and may be made to the Company's principal
Canadian operating subsidiaries. The Company has an option to increase the
maximum borrowings under the new facility to $250 million prior to its maturity.
The facility matures on October 30, 2007, unless extended for up to one
additional year period with the consent of the lenders. Amounts borrowed under
this facility bear interest, at the Company's election, at either:
- a variable rate equal to LIBOR (or, in the case of Canadian
dollar denominated loans, the Bankers' Acceptance discount rate)
plus a margin ranging from 1.5% to 2.5%; or
- an alternate base rate equal to the higher of the bank's prime
rate and the federal funds effective rate plus 0.5% (or, in the
case of Canadian dollar denominated loans, the Canadian Prime
Rate) plus a margin ranging from 0.5% to 1.5%, depending upon the
ratio of total debt to EBITDA as defined in the credit facility.
Commitment fees ranging from 0.375% to 0.5% per year are paid on the
undrawn portion of the facility, depending upon our leverage ratio.
The credit facility is guaranteed by all of the Company's active
domestic subsidiaries and, in some cases, the Company's Canadian and other
foreign subsidiaries. The credit facility is secured by a first priority lien on
all the Company's inventory, accounts receivable and other material tangible and
intangible assets, as well as those of the Company's active subsidiaries.
However, no more than 65% of the voting stock of any foreign subsidiary is
required to be pledged if the pledge of any greater percentage would result in
adverse tax consequences.
The credit facility contains negative covenants that restrict the
Company's ability to borrow additional funds encumber assets, pay dividends,
sell assets except in the normal course of business and enter into other
significant transactions.
Under the Company's credit facility, the occurrence of specified change
of control events involving our company would constitute an event of default
that would permit the banks to, among other things, accelerate the maturity of
the facility and cause it to become immediately due and payable in full.
As of December 31, 2003, we had $128.7 million outstanding under this
facility and an additional $10.3 million of outstanding letters of credit
leaving $86.0 million available to be drawn under the facility. The Company's
weighted average interest rate on the Company's outstanding borrowings under
this facility at December 31, 2003 was 3.6%.
In conjunction with executing the senior secured revolving credit
facility on October 30, 2003, the Company recognized additional non-cash
interest expense of $1.2 million, after taxes, for the write-off of deferred
financing costs related to its prior credit facility.
57
On February 28, 2003, the Company renewed its overdraft credit facility
providing for borrowings totaling (pound)5.0 million for UK operations. Interest
is payable quarterly at a margin of 1.5% per annum over the bank's variable base
rate. All borrowings under this facility are payable on demand. No amounts were
outstanding under this facility at December 31, 2003.
7. POSTRETIREMENT HEALTHCARE AND OTHER INSURANCE BENEFITS
The Company provides healthcare and other insurance benefits for
approximately 360 eligible retired employees and dependent spouses. This plan is
no longer available to current employees. The healthcare plans are contributory
and contain other cost-sharing features such as deductibles, lifetime maximums,
and co-payment requirements.
2003 2002
------- -------
(IN THOUSANDS)
Changes in accumulated postretirement benefit
obligation:
Benefit obligation at beginning of year......... $ 7,356 $ 7,156
Interest cost on accumulated postretirement
benefit obligation............................. 311 514
Benefits paid................................... (584) (861)
Actuarial (gain) loss........................... (801) 547
Buy-out payments................................ (1,327) --
Reduction due to buy-out of medical benefits.... (986) --
Reduction due to termination of Medicare Part B
benefits....................................... (945) --
------- -------
Benefit obligation at end of year................. $ 3,024 $ 7,356
======= =======
2003 2002 2001
------- ------- ------
(IN THOUSANDS)
Components of net periodic benefit cost:
Interest cost on accumulated postretirement
benefit obligation....................... $ 311 $ 514 $ 618
Amortization of net loss (gain)............ (22) (23) (16)
Amortization of prior service cost......... 46 79 79
Gain due to buy-out of medical benefits.... (584) -- --
Gain due to termination of Medicare Part B
benefits................................. (792) -- --
------- ------- ------
Total net periodic benefit cost (benefit).... $(1,041) $ 570 $ 681
======= ======= ======
2003 2002
------- -------
(IN THOUSANDS)
Accumulated postretirement benefit obligation:
Retirees and dependent spouses.................. $ 2,880 $ 7,064
Other plan participants......................... 144 292
------- -------
Total accumulated postretirement benefit
obligation.................................... 3,024 7,356
Unrecognized prior service cost................. (348) (696)
Unrecognized net gain (loss).................... 751 (280)
------- -------
Total liability included in the consolidated
and combined balance sheets................. 3,427 6,380
Less: Current portion............................. (765) (1,100)
------- -------
Noncurrent liability........................ $ 2,662 $ 5,280
======= =======
The healthcare plans are not funded, and the Company's policy is to pay
these benefits as they are incurred.
In 2003, the Company terminated Medicare Part B benefits and offered a
buy-out to plan participants, which resulted in a total reduction of $3.3
million in the accumulated benefit obligation and a gain of $1.4 million. The
gain was credited to expense during the second and third quarters of 2003.
The 2003 net periodic benefit cost and the accumulated benefit
obligation was determined under an actuarial assumption using a healthcare cost
trend rate of 9.0% for medical and 12.0% for prescription drugs, gradually
declining to approximately 5% in the year 2009 and thereafter over the projected
payout period of the benefits. The accumulated benefit obligations were
determined using an assumed discount rate of 6.00% and 6.75% at December 31,
2003 and 2002, respectively. Under the plan's provisions, the Company's
prescription costs are capped at annual benefit limits.
A one percentage-point increase or decrease in the assumed healthcare
cost trend rates would be immaterial to the accumulated postretirement benefit
obligation and net periodic benefit cost at December 31, 2003.
58
In January 2004, Financial Staff Position No. FAS 106-1 was issued
which addresses the accounting and disclosure requirements related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the
"Act") which was enacted on December 8, 2003. The Act introduced both a Medicare
prescription drug benefit and a federal subsidy to sponsors of retiree
health-care plans that provide a benefit at least "actuarially equivalent" to
the Medicare benefit. The effects of the Act are not reflected in the
measurement of our accumulated postretirement benefit obligation or net periodic
benefit cost as the Company has elected to defer recognizing the effects of the
Act until authoritative guidance on the accounting for the federal subsidy is
issued, or until certain other events occur that would require remeasurement of
the plan's benefit obligation. The Company does not believe the Act will have a
material impact on the measurement of our accumulated postretirement benefit
obligation or net periodic benefit cost; however, when the authoritative
guidance is issued, it could require us to change previously reported
information.
8. RETIREMENT PLANS
Prior to January 2002, the Company sponsored a number of defined
contribution plans. Effective in January 2002, the Company merged its domestic
defined contribution plans into a single plan sponsored by the Company.
Participation in these plans is available to substantially all employees.
The Company recognized expense of $2.9 million, $2.5 million and $1.7
million related to its various defined contribution plans during the years ended
December 31, 2003, 2002 and 2001, respectively.
9. PREFERRED STOCK
Cash dividends paid on preferred stock in 2001 related to preferred
stock that was either repaid in cash or converted to common stock in connection
with the Offering completed in February 2001 (See Note 2).
10. INCOME TAXES
Consolidated pre-tax income for the years ended December 31, 2003, 2002
and 2001 consisted of the following (in thousands):
2003 2002 2001
-------- -------- --------
US operations............. $ 22,984 $ 26,118 $ 21,115
Foreign operations........ 35,670 24,915 25,211
-------- -------- --------
Total................ $ 58,654 $ 51,033 $ 46,326
======== ======== ========
The components of the income tax provision (benefit) for the years
ended December 31, 2003, 2002 and 2001 consisted of the following (in
thousands):
2003 2002 2001
-------- -------- ---------
Current:
Federal.................. $ 2,047 $ (3,797) $ 2,451
State.................... 464 1,482 1,450
Foreign.................. 10,997 8,775 9,657
-------- -------- ---------
13,508 6,460 13,558
-------- -------- ---------
Deferred:
Federal.................. (918) 3,209 (12,153)
State.................... 256 374 (209)
Foreign.................. 1,376 1,314 858
-------- -------- ---------
714 4,897 (11,504)
-------- -------- ---------
Total Provision....... $ 14,222 $ 11,357 $ 2,054
======== ======== =========
59
The provision for taxes differs from an amount computed at statutory
rates as follows for the years ended December 31, 2003, 2002 and 2001 (in
thousands):
2003 2002 2001
-------- -------- ---------
Federal tax expense at statutory rates..... $ 20,529 $ 17,860 $ 16,490
Foreign income tax rate differential....... 610 2,029 2,472
Nondeductible expenses..................... 1,068 435 2,867
Foreign distributions...................... -- -- 6,650
State tax expense (benefit), net of federal 468 1,208 1,296
benefits..................................
Manufacturing and processing profits (723) (660) (782)
deduction.................................
Adjustment of valuation allowance.......... (7,722) (8,452) (26,939)
Other, net................................. (8) (1,063) --
--------- -------- ---------
Net income tax provision.............. $ 14,222 $ 11,357 $ 2,054
======== ======== =========
The significant items giving rise to the deferred tax assets and
liabilities as of December 31, 2003 and 2002 are as follows (in thousands):
2003 2002
--------- ---------
Deferred tax assets:
Net operating loss carryforward...... $ 22,134 $ 25,796
Allowance for doubtful accounts...... 537 563
Inventory............................ 1,177 1,099
Employee benefits.................... 4,183 3,017
Intangibles.......................... 750 1,037
Reserves............................. 608 440
Accrued liabilities.................. 441 796
Other................................ 3,441 3,187
--------- ---------
Gross deferred tax asset............. 33,271 35,935
Less: valuation allowance............ (12,030) (19,652)
--------- ---------
Net deferred tax asset............... 21,241 16,283
--------- ---------
Deferred tax liabilities:
Depreciation......................... (34,423) (28,372)
Unearned revenue..................... (554) (501)
Inventory............................ (619) (606)
Other................................ (1,939) (1,274)
--------- ---------
Deferred tax liability............... (37,535) (30,753)
--------- ---------
Net deferred tax liability........ $ (16,294) $ (14,470)
========= =========
Reclassifications of the Company's deferred tax balance based on net
current items and net non-current items as of December 31, 2003 is as follows
(in thousands):
2003
---------
Current asset
Current deferred tax asset............. $ 3,117
Long term deferred tax liability...... (19,411)
---------
Net deferred tax liability............. $ (16,294)
=========
For US federal income tax purposes, the Company has net operating loss
carryforwards of approximately $63.2 million for regular income taxes that will
expire in the years 2008 through 2020. The Company's net operating loss
carryforwards are subject to limitations under Section 382 of the Internal
Revenue Code of 1986, as amended. Based on these limitations, the years the
carryforwards expire, and the uncertainty in achieving levels of taxable income
required for their utilization, the Company has provided a valuation allowance
on a portion of these carryforwards. The Company has federal alternative minimum
tax net operating loss carryforwards of $44.5 million, which will expire in the
years 2010 through 2020.
The Company has $2.9 million of net operating loss carryforwards
associated with its Canadian subsidiary's Chilean operations as of December 31,
2003. These losses may be carried forward indefinitely; however, such losses may
only be used to offset future Chilean taxable income. Accordingly, the Company
has provided a full valuation allowance against the associated deferred tax
asset.
Appropriate US and foreign income taxes have been provided for earnings
of foreign subsidiary companies that are expected to be remitted in the near
future. The cumulative amount of undistributed earnings of foreign subsidiaries
that the Company intends to permanently reinvest and upon which no deferred US
income taxes have been provided is $98.7 million at December 31, 2003. Upon
distribution of these earnings in the form of dividends or otherwise, the
Company may be subject to US income taxes and foreign withholding taxes. It is
not practical,
60
however, to estimate the amount of taxes that may be payable on the eventual
remittance of these earnings after consideration of available foreign tax
credits.
At December 31, 2003, the Company had a valuation allowance of $12.0
million, which reflects a $7.6 million decrease from the amount at December 31,
2002. The reduction in the valuation allowance is being made because management
believes, based on the weight of available evidence, that it is more likely than
not that this additional portion of the Company's net operating losses will be
utilized prior to the expiration of its carryforward period.
During the year ended December 31, 2003, the Company recognized a tax
benefit triggered by employee exercises of stock options totaling $1.6 million.
Such benefit was credited to additional paid-in capital.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the years ended December 31, 2003, 2002 and 2001 for
interest and income taxes was as follows (in thousands):
2003 2002 2001
------- ------- -------
Interest.......................... $ 7,721 $ 4,728 $12,366
Income taxes, net of refunds...... $12,901 $ 9,446 $12,736
Components of cash used for acquisitions as reflected in the
consolidated statements of cash flows for the years ended December 31, 2003,
2002 and 2001 are summarized as follows (in thousands):
2003 2002 2001
--------- --------- --------
Fair value of assets acquired and goodwill.... $ 18,868 $ 85,132 $ 7,766
Liabilities assumed........................... (2,000) (13,122) (1,795)
Noncash consideration......................... -- (1,950) --
Less: cash acquired........................... (582) (5,213) (852)
--------- --------- --------
Cash used in acquisition of businesses........ $ 16,286 $ 64,847 $ 5,119
========= ========= ========
In connection with acquisitions made in 2002, the Company had non-cash
transactions consisting of the issuance of $2.0 million of notes payable and the
assumption of capital leases totaling $3.3 million.
12. COMMITMENTS AND CONTINGENCIES
The Company leases a portion of its equipment, office space, computer
equipment, automobiles and trucks under leases which expire at various dates.
Minimum future operating lease obligations in effect at December 31,
2003, are as follows (in thousands):
OPERATING
LEASES
---------
2004........................ $ 3,769
2005........................ 2,605
2006........................ 1,355
2007........................ 691
2008........................ 509
Thereafter.................. 2,678
---------
Total.................. $ 11,607
=========
Rental expense under operating leases was $4.9 million, $4.3 million
and $3.9 million for the years ended December 31, 2003, 2002 and 2001,
respectively.
As of December 31, 2003, the Company had entered into forward purchase
option contracts through February 25, 2004 with a bank totaling $5.0 million for
the purchase of foreign currency as a hedge to expected future billings. The
contract purchase rate was favorable to the December 31, 2003 currency exchange
rate by almost 15%. We have incurred no material gains or losses from foreign
currency hedging activities.
The Company is a party to various pending or threatened claims,
lawsuits and administrative proceedings seeking damages or other remedies
concerning its commercial operations, products, employees and other matters,
61
including occasional claims by individuals alleging exposure to hazardous
materials as a result of its products or operations. Some of these claims relate
to matters occurring prior to its acquisition of businesses, and some relate to
businesses it has sold. In certain cases, the Company is entitled to
indemnification from the sellers of businesses and in other cases, it has
indemnified the buyers of businesses from it. Although the Company can give no
assurance about the outcome of pending legal and administrative proceedings and
the effect such outcomes may have on it, management believes that any ultimate
liability resulting from the outcome of such proceedings, to the extent not
otherwise provided for or covered by insurance, will not have a material adverse
effect on its consolidated financial position, results of operations or
liquidity.
13. RELATED-PARTY TRANSACTIONS
The Company incurred legal fees totaling $240,000 in 2001 for services
rendered by a law firm in connection with a possible acquisition of a company. A
member of the Company's Board of Directors is a partner with that law firm. No
transaction resulted from the acquisition effort.
The company currently rents land and buildings from a former officer of
a subsidiary of the Company and pays a monthly rent of $5,556. Such officer was
the previous owner of a business acquired by Oil States.
14. STOCK-BASED COMPENSATION
In October 1995, the FASB issued SFAS No. 123, "Accounting for
Stock-Based Compensation," which requires the Company to record stock-based
compensation at fair value. In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock Based Compensation -- Transition and Disclosure." The
Company has adopted the disclosure requirements of SFAS No. 148 and has elected
to record employee compensation expense utilizing the intrinsic value method
permitted under Accounting Principles Board (APB) Opinion No. 25, "Accounting
for Stock Issued to Employees."
The Company accounts for its employee stock-based compensation plan
under APB Opinion No. 25 and its related interpretations. Accordingly, any
deferred compensation expense would be recorded for stock options based on the
excess of the market value of the common stock on the date the options were
granted over the aggregate exercise price of the options. This deferred
compensation would be amortized over the vesting period of each option. The
Company is authorized to grant common stock based awards covering 5,700,000
shares of common stock under the 2001 Equity Participation Plan, as amended and
restated, (the Stock Option Plan), to employees, consultants and directors with
amounts, exercise prices and vesting schedules determined by the Company's
compensation committee of its Board of Directors. All option grants made from
February 2001 to December 2003 have been priced at the closing price on the day
of grant, vest 25% per year and have a ten-year life. Because the exercise price
of options granted under the Stock Option Plan have been equal to or greater
than the market price of the Company's stock on the date of grant, no
compensation expense related to this plan has been recorded. Had compensation
expense for its Stock Option Plan been determined consistent with SFAS No. 123
utilizing the fair value method, the Company's net income and earnings per share
at December 31, 2003, 2002 and 2001, would have been as follows (in thousands,
except per share amounts):
2003 2002 2001
--------- -------- --------
Net income attributable to common shares as reported... $ 44,432 $ 39,676 $ 42,635
Deduct: Total stock-based employee compensation
expense determined under fair value based method for
all awards, net of related tax effects................ (2,195) (1,950) (1,540)
--------- -------- --------
Pro forma net income................................... $ 42,237 $ 37,726 $ 41,095
========= ======== ========
Net income attributable to common shares per share,
as reported:
Basic................................................ $ 0.92 $ 0.82 $ 0.94
Diluted.............................................. 0.90 0.81 0.93
Pro forma net income attributable to common shares,
as if fair value method had been applied to all
awards:
Basic................................................ $ 0.87 $ 0.78 $ 0.91
Diluted.............................................. 0.86 0.77 0.89
62
The following table summarizes stock option activity for each of the
years ended December 31, 2001, 2002 and 2003:
STOCK OPTION PLAN
---------------------------
WEIGHTED
AVERAGE
OPTIONS EXERCISE PRICE
---------- --------------
Balance at December 31, 2000........... 836,871 8.31
Granted.............................. 1,389,060 8.02
Exercised............................ (75,820) 5.94
Forfeited............................ (94,619) 7.95
----------
Balance at December 31, 2001........... 2,055,492 8.24
Granted.............................. 730,250 8.27
Exercised............................ (190,951) 6.31
Forfeited............................ (155,718) 8.19
----------
Balance at December 31, 2002........... 2,439,073 8.40
Granted.............................. 1,020,750 11.31
Exercised............................ (638,442) 6.39
Forfeited............................ (140,638) 12.28
----------
Balance at December 31, 2003........... 2,680,743 9.78
Exercisable at December 31, 2001....... 717,533 7.98
Exercisable at December 31, 2002....... 976,605 8.22
Exercisable at December 31, 2003....... 805,050 9.18
The following table summarizes information for stock options
outstanding at December 31, 2003:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------- ----------------------
WEIGHTED
NUMBER AVERAGE WEIGHTED NUMBER WEIGHTED
OUTSTANDING REMAINING AVERAGE EXERCISABLE AVERAGE
RANGE OF EXERCISE AS OF CONTRACTUAL EXERCISE AS OF EXERCISE
PRICES 12/31/2003 LIFE PRICE 12/31/2003 PRICE
- -------------------- ----------- ----------- -------- ----------- ---------
$5.6659 - $ 6.5432 163,881 1.62 $ 5.9957 159,547 $ 6.0018
$8.0000 - $ 8.0000 611,936 8.12 $ 8.0000 137,754 $ 8.0000
$8.1790 - $ 8.6529 176,126 6.33 $ 8.3459 100,876 $ 8.3578
$9.0000 - $ 9.0000 644,700 7.11 $ 9.0000 295,700 $ 9.0000
$9.8148 - $11.4506 61,481 4.37 $ 10.5853 43,669 $ 10.6160
$11.4900 - $30.0000 1,022,619 8.51 $ 12.1500 67,504 $ 20.2427
--------- ---- --------- ------- ---------
$5.6659 - $30.0000 2,680,743 7.42 $ 9.7831 805,050 $ 9.1846
At December 31, 2003, 2,014,044 options were available for future grant
under the Stock Option Plan.
The weighted average fair values of options granted during 2003, 2002,
and 2001 were $4.55, $5.31, and $5.48 per share, respectively. The fair value of
each option grant is estimated on the date of grant using the Black-Scholes
option pricing model with the following weighted average assumptions used for
grants in 2003, 2002, and 2001, respectively: risk-free interest rates of 3.0%,
5.2%, and 5.0%, no expected dividend yield, expected lives of 5.5, 10.0, and 8.3
years, and an expected volatility of 37%, 45% and 45%.
DEFERRED COMPENSATION PLAN
The Company maintains a deferred compensation plan ("Deferred
Compensation Plan"). This plan is available to directors and certain officers
and managers of the Company. The plan allows participants to defer all or a
portion of their directors fees and/or salary and annual bonuses, as applicable,
and it permits the Company to make discretionary contributions to any
participant's account. All contributions to the participants' accounts vest
immediately. The Deferred Compensation Plan does not have dollar limits on
tax-deferred contributions. The assets of the Deferred Compensation Plan are
held in a Rabbi Trust ("Trust") and, therefore, are available to satisfy the
claims of the Company's creditors in the event of bankruptcy or insolvency of
the Company. Participants have the ability to direct the Plan Administrator to
invest the assets in their accounts, including any discretionary contributions
by the Company, in pre-approved mutual funds held by the Trust. Prior to
November 1, 2003, participants also had the ability to direct the Plan
Administrator to invest the assets in their accounts in Company common stock. In
addition, participants currently have the right to request that the Plan
Administrator re-allocate the portfolio of investments (i.e. cash or mutual
funds) in the participants' individual accounts within the Trust. Current
balances invested in Company common stock may not be further increased. Company
contributions are in the form of cash. Distributions from the plan are generally
made upon the participants' termination as a director
63
and/or employee, as applicable, of the Company. Participants receive payments
from the Plan in cash. At December 31, 2003, the balance of the assets in the
Trust totaled $2.4 million, including 33,423 shares of common stock of the
Company reflected as treasury stock at a value of $0.3 million. The Company
accounts for the Deferred Compensation Plan in accordance with EITF 97-14,
"Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held
in a Rabbi Trust and Invested."
Assets of the Trust, other than common stock of the Company, are
invested in nine funds covering a variety of securities and investment
strategies. These mutual funds are publicly quoted and reported at market value.
The Company accounts for these investments in accordance with SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities." The Trust
also holds common shares of the Company. The Company's common stock that is held
by the Trust has been classified as treasury stock in the stockholders' equity
section of the consolidated balance sheet. The market value of the assets held
by the Trust, exclusive of the market value of the shares of the Company's
common stock that are reflected as treasury stock, at December 31, 2003 was $2.0
million and is classified as "Other noncurrent assets" in the consolidated
balance sheet. Amounts payable to the plan participants at December 31, 2003,
including the market value of the shares of the Company's common stock that are
reflected as treasury stock, was $2.5 million and is classified as "Other
liabilities" in the consolidated balance sheet.
In accordance with EITF 97-14, all market value fluctuations of the
Trust assets have been reflected in the consolidated and combined statements of
income. Increases or decreases in the value of the plan assets, exclusive of the
shares of common stock of the Company, have been included as compensation
adjustments in the respective statements of income. Increases or decreases in
the market value of the deferred compensation liability, including the shares of
common stock of the Company held by the Trust, while recorded as treasury stock,
are also included as compensation adjustments in the consolidated and combined
statements of income. In response to the changes in total market value of the
Company's common stock held by the Trust, the Company recorded net compensation
expense adjustments of $0.1 million in both 2003 and 2002.
15. SEGMENT AND RELATED INFORMATION
In accordance with SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," the Company has identified the following
reportable segments: offshore products, wellsite services and tubular services.
The Company's reportable segments are strategic business units that offer
different products and services. They are managed separately because each
business requires different technology and marketing strategies. Most of the
businesses were acquired as a unit, and the management at the time of the
acquisition was retained.
Financial information by industry segment for each of the three years
ended December 31, 2003, 2002 and 2001, is summarized in the following table in
thousands. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies.
CORPORATE
OFFSHORE WELLSITE TUBULAR AND
PRODUCTS SERVICES SERVICES ELIMINATIONS TOTAL
---------- --------- --------- ------------ ---------
2003
Revenues from unaffiliated
customers..................... $ 231,897 $ 256,060 $ 235,724 $ -- $ 723,681
Depreciation and amortization... 7,765 19,448 642 50 27,905
Operating income (loss)......... 27,850 37,245 5,949 (5.877) 65,167
Cash capital expenditures....... 10,778 30,178 188 117 41,261
Total assets.................... 257,227 308,266 139,305 12,388 717,186
2002
Revenues from unaffiliated
customers..................... $ 190,638 $ 209,842 $ 216,368 $ -- $ 616,848
Depreciation and amortization... 6,056 16,562 593 101 23,312
Operating income (loss)......... 27,249 27,372 5,442 (5,503) 54,560
Cash capital expenditures....... 6,593 19,302 187 4 26,086
Total assets.................... 242,701 254,949 137,112 9,454 644,216
2001
Revenues from unaffiliated
customers..................... $ 129,349 $ 239,777 $ 302,079 $ -- $ 671,205
Depreciation and amortization... 6,420 16,522 1,786 3,311 28,039
Operating income (loss)......... 6,588 47,409 10,456 (8,757) 55,696
Cash capital expenditures....... 4,708 24,131 732 100 29,671
Total assets.................... 136,527 241,621 148,491 3,244 529,883
64
Financial information by geographic segment for each of the three years
ended December 31, 2003, 2002 and 2001, is summarized below in thousands.
Revenues in the US include export sales. Revenues are attributable to countries
based on the location of the entity selling the products or performing the
services. Total assets are attributable to countries based on the physical
location of the entity and its operating assets and do not include intercompany
balances.
UNITED UNITED OTHER
STATES CANADA KINGDOM NON-US TOTAL
-------- --------- ------- ------- ---------
2003
Revenues from unaffiliated
customers.............. $511,895 $ 126,352 $56,556 $28,878 $ 723,681
Long-lived assets......... 317,605 82,529 17,969 11,006 429,109
2002
Revenues from unaffiliated
customers.............. $427,578 $ 96,087 $53,023 $40,160 $ 616,848
Long-lived assets......... 292,056 67,721 16,184 12,449 388,410
2001
Revenues from unaffiliated
customers.............. $451,690 $ 108,685 $41,138 $69,692 $ 671,205
Long-lived assets......... 231,086 67,841 17,698 10,637 327,262
One customer accounted for between 5% and 7% of the Company's revenues
in each of the years ended December 31, 2003, 2002 and 2001. No other customer
accounted for more than 5% of the Company's revenues in the periods presented.
16. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following table summarizes quarterly financial information for
2003, 2002 and 2001 (in thousands, except per share amounts):
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------- --------- --------- ---------
2003
Revenues(1)................... $ 185,577 $ 163,564 $ 177,170 $ 197,370
Gross profit*................. 40,609 36,233 37,815 35,910
Net income ................... 13,369 10,154 11,334 9,575
Basic earnings per share...... 0.28 0.21 0.23 0.20
Diluted earnings per share.... 0.27 0.21 0.23 0.19
2002
Revenues(1)................... $ 150,600 $ 150,839 $ 154,595 $ 160,814
Gross profit*................. 30,447 29,149 32,839 37,360
Net income.................... 9,808 8,219 10,188 11,461
Basic earnings per share...... 0.20 0.17 0.21 0.24
Diluted earnings per share.... 0.20 0.17 0.21 0.23
2001
Revenues(1)................... $ 142,976(2) $ 175,333 $ 173,510 $ 179,386
Gross profit*................. 34,798 33,711 33,120 31,784
Net income.................... 11,030 10,261 10,302 11,083
Basic earnings per share 0.30 0.21 0.21 0.23
Diluted earnings per share: 0.29 0.21 0.21 0.23
Earnings per share are computed independently for each of the quarters
presented. Therefore, the sum of the quarterly earnings per share may not equal
the total computed for the year.
- ----------
* Represents "revenues" less "product costs" and "service and other costs"
included in the Company's consolidated and combined statements of operations.
(1) The Company's business in the well site services segment, particularly in
Canada, is seasonal with the highest activity occurring in the winter
months.
65
(2) Effective February 14, 2001, the Company acquired Sooner and results of
Sooner are included from acquisition date.
17. VALUATION ALLOWANCES
Activity in the valuation accounts was as follows (in thousands):
BALANCE AT CHARGED TO TRANSLATION BALANCE AT
BEGINNING COSTS AND AND OTHER, END OF
OF PERIOD EXPENSES DEDUCTIONS NET PERIOD
---------- ---------- ---------- ----------- ----------
Year Ended December 31, 2003:
Allowance for doubtful
accounts receivable....... $ 2,287 $ 702 $ (633) $(335) $ 2,021
Reserve for inventories...... 4,778 380 (29) 150 5,279
Reserves related to
discontinued operations... 5,757 -- (972) -- 4,785
Year Ended December 31, 2002:
Allowance for doubtful
accounts receivable....... $ 2,733 $ 221 $ (1,266) $ 599 $ 2,287
Reserve for inventories...... 5,697 (198) (810) 89 4,778
Reserves related to
discontinued operations... 6,109 -- (352) -- 5,757
Year Ended December 31, 2001:
Allowance for doubtful
accounts receivable....... $ 2,155 $ 1,064 $ (729) $ 243 $ 2,733
Reserve for inventories...... 4,915 1,119 (740) 403 5,697
Reserves related to
discontinued operations... 6,512 -- (403) -- 6,109
18. SUBSEQUENT EVENT (UNAUDITED)
In January 2004, the Company completed the acquisition of several
related rental tool companies. The companies, based in South Texas, are leading
providers of thru-tubing services and ancillary equipment rentals. These
companies have been combined with our rental tool subsidiary, and will report
through the Well Site Services segment. The Company paid a total of $34.7
million in cash for the stock of the companies which was funded by the Company's
credit facility. Combined revenues for the acquired companies for the year ended
December 31, 2003 were approximately $15.4 million.
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EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.1 -- Amended and Restated Certificate of Incorporation (incorporated
by reference to Exhibit 3.1 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, as filed with
the Commission on March 30, 2001).
3.2 -- Amended and Restated Bylaws (incorporated by reference to
Exhibit 3.2 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission on
March 30, 2001).
3.3 -- Certificate of Designations of Special Preferred Voting Stock of
Oil States International, Inc. (incorporated by reference to
Exhibit 3.3 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission on
March 30, 2001).
4.1 -- Form of common stock certificate (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-1
(File No. 333-43400)).
4.2 -- Amended and Restated Registration Rights Agreement (incorporated
by reference to Exhibit 4.2 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2000, as filed with
the Commission on March 30, 2001).
4.3 -- First Amendment to the Amended and Restated Registration Rights
Agreement dated May 17, 2002 (incorporated by reference to
Exhibit 4.3 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2002, as filed with the Commission on
March 13, 2003).
10.1 -- Combination Agreement dated as of July 31, 2000 by and among Oil
States International, Inc., HWC Energy Services, Inc., Merger
Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI
Group Inc. (incorporated by reference to Exhibit 10.1 to the
Company's Registration Statement on Form S-1 (File No.
333-43400)).
10.2 -- Plan of Arrangement of PTI Group Inc. (incorporated by reference
to Exhibit 10.2 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2000, as filed with the Commission
on March 30, 2001).
10.3 -- Support Agreement between Oil States International, Inc. and PTI
Holdco (incorporated by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended December
31, 2000, as filed with the Commission on March 30, 2001).
10.4 -- Voting and Exchange Trust Agreement by and among Oil States
International, Inc., PTI Holdco and Montreal Trust Company of
Canada (incorporated by reference to Exhibit 10.4 to the
Company's Annual Report on Form 10-K for the year ended December
31, 2000, as filed with the Commission on March 30, 2001).
10.5** -- 2001 Equity Participation Plan (incorporated by reference to
Exhibit 10.5 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission on
March 30, 2001).
10.6* -- Deferred Compensation Plan effective November 1, 2003.
10.7** -- Annual Incentive Compensation Plan (incorporated by reference to
Exhibit 10.7 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000, as filed with the Commission on
March 30, 2001).
10.8** -- Executive Agreement between Oil States International, Inc. and
Douglas E. Swanson (incorporated by reference to Exhibit 10.8 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 2000, as filed with the Commission on March 30,
2001).
10.9** -- Executive Agreement between Oil States International, Inc. and
Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 2000, as filed with the Commission on March 30,
2001).
10.10** -- Form of Executive Agreement between Oil States International,
Inc. and Named Executive Officer (Mr. Hughes) (incorporated by
reference to Exhibit 10.10 of the Company's Registration
Statement on Form S-1 (File No. 333-43400)).
10.11** -- Form of Change of Control Severance Plan for Selected Members of
Management (incorporated by reference to Exhibit 10.11 of the
Company's Registration Statement on Form S-1 (File No.
333-43400)).
67
10.12 -- Credit Agreement, dated as of October 30, 2003, among Oil States
International, Inc., the Lenders named therein and Wells Fargo
Bank Texas, National Association, as Administrative Agent and
U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian
Administrative Agent and Canadian Collateral Agent; Hibernia
National Bank and Royal Bank of Canada, as Co-Syndication Agents
and Bank One, NA and Credit Lyonnais New York Branch, as
Co-Documentation Agents (incorporated by reference to Exhibit
10.12 to the Company's Quarterly Report on Form 10Q for the
three months ended September 30, 2003, as filed with the
Commission on November 11, 2003.)
10.13A** -- Restricted Stock Agreement, dated February 8, 2001, between Oil
States International, Inc. and Douglas E. Swanson (incorporated
by reference to Exhibit 10.13A to the Company's Quarterly Report
on Form 10-Q for the three months ended March 31, 2002, as filed
with the Commission on May 15, 2001).
10.13B** -- Restricted Stock Agreement, dated February 22, 2001, between Oil
States International, Inc. and Douglas E. Swanson (incorporated
by reference to Exhibit 10.13B to the Company's Quarterly Report
on Form 10-Q for the three months ended March 31, 2002, as filed
with the Commission on May 15, 2001).
10.14** -- Form of Indemnification Agreement (incorporated by reference to
Exhibit 10.14 of the Company's Registration Statement on Form
S-1 (File No. 333-43400)).
10.15** -- Form of Executive Agreement between Oil States International,
Inc. and named Executive Officer (Mr. Slator) (incorporated by
reference to Exhibit 10.16 to the Company's Annual Report on
Form 10-K for the year ended December 31, 2001, as filed with
the Commission on March 1, 2002).
10.16** -- Douglas E. Swanson contingent option award dated as of February
11, 2002 (incorporated by reference to Exhibit 10.17 to the
Company's Quarterly Report on Form 10-Q for the three months
ended September 30, 2002 as filed with the Commission on
November 13, 2002).
10.17** -- Form of Executive Agreement between Oil States International,
Inc. and named executive officer (Mr. Trahan) (incorporated by
reference to Exhibit 10.16 to the Company's Quarterly Report on
Form 10-Q for the three months ended June 30, 2002, as filed
with the Commission on August 13, 2002).
21.1* -- List of subsidiaries of the Company.
23.1* -- Consent of Ernst & Young LLP
24.1* -- Powers of Attorney for Directors
31.1* -- Certification of Chief Executive Officer of Oil States
International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934.
31.2* -- Certification of Chief Financial Officer of Oil States
International, Inc. pursuant to Rules 13a-14(a) under the
Securities Exchange Act of 1934.
32.1*** -- Certification of Chief Executive Officer of Oil States
International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b)
under the Securities Exchange Act of 1934.
32.2*** -- Certification of Chief Financial Officer of Oil States
International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b)
under the Securities Exchange Act of 1934.
- ----------
* Filed herewith
** Management contracts or compensatory plans or arrangements
*** Furnished herewith
68