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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, 2008
 
Commission file no. 1-16337
 
Oil States International, Inc.
(Exact name of registrant as specified in its charter)
 
     
Delaware
(State or other Jurisdiction of
Incorporation or Organization)
  76-0476605
(I.R.S. Employer
Identification No.)
 
Three Allen Center, 333 Clay Street, Suite 4620, 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 if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
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.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act.  Yes o     No þ
 
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, 2008)
  $ 3,136,507,402  
 
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 11, 2009
  Common Stock, par value $.01 per share   49,501,436 shares
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the Registrant’s Definitive Proxy Statement for the 2009 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
 
             
  Business     2-15  
  Risk Factors     15-25  
  Unresolved Staff Comments     25  
  Properties     25-26  
  Legal Proceedings     26  
  Submission of Matters to a Vote of Security Holders     26  
 
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     27-29  
  Selected Financial Data     29-31  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     31-45  
  Quantitative and Qualitative Disclosures About Market Risk     45  
  Financial Statements and Supplementary Data     45  
  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     45  
  Controls and Procedures     45-46  
  Other Information     46  
 
  Directors, Executive Officers and Corporate Governance     46  
  Executive Compensation     46  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     47  
  Certain Relationships and Related Transactions, and Director Independence     47  
  Principal Accountant Fees and Services     47  
 
  Exhibits and Financial Statement Schedules     47-50  
    51  
    52  
 EX-10.21
 EX-10.22
 EX-10.23
 EX-10.24
 EX-10.25
 EX-10.26
 EX-21.1
 EX-23.1
 EX-24.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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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.
 
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 strategic transactions, 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:
 
  •  the level of demand for and supply of oil and gas;
 
  •  fluctuations in the prices of oil and gas;
 
  •  the level of drilling and completion activity;
 
  •  the level of offshore oil and gas developmental activities;
 
  •  current recessionary economic conditions and the depth and duration of the recession;
 
  •  our ability to find and retain skilled personnel;
 
  •  the availability and cost of capital; and
 
  •  the other factors identified under the caption “Risks Factors”,
 
Item 1.   Business
 
Our Company
 
Oil States International, Inc. (the Company or Oil States), through its subsidiaries, is 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, West Africa, the North Sea, Canada, South America and Southeast and Central Asia. Our customers include many of the national oil companies, major and independent oil and gas companies and other oilfield service


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companies. We operate in three principal business segments — offshore products, tubular services and well site services — and have established a leadership position in certain of our product or service offerings in each segment.
 
Available Information
 
The Company maintains a website with the address www.oilstatesintl.com. The Company is not including the information contained on the Company’s website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K. The Company makes available free of charge through its website its Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after the Company electronically files such material with, or furnishes such material to, the Securities and Exchange Commission (SEC). The Board of Directors of the Company documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company’s corporate governance guidelines and its code of business conduct and ethics, as well as the charters for the committees of the Board (Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee) may also be viewed at the Company’s website. Copies of such documents will be sent to shareholders free of charge upon written request of the corporate secretary at the address shown on the cover page of this Form 10-K.
 
In accordance with New York Stock Exchange (NYSE) Rules, on June 6, 2008, the Company filed the annual certification by our CEO that, as of the date of the certification, the Company was in compliance with the NYSE’s corporate governance listing standards.
 
Our Background
 
Oil States International, Inc. was originally incorporated in July 1995 and completed its initial public offering in February 2001. In July 2000, Oil States International, Inc., including its principal operating subsidiaries, Oil States Industries, Inc. (Oil States Industries), 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 the Company 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.
 
Our Business Strategy
 
We have in past years grown our business lines both organically and through strategic acquisitions. Our investments are focused in growth areas and on areas where we can expand market share and where we can achieve attractive returns. Currently, we see opportunities in the oil sands developments in Canada and in the expansion of our capabilities to manufacture and assemble deepwater capital equipment. Current economic conditions have led us to emphasize appropriate reductions in our capital spending and operating expenses consistent with the decline in demand for our services as producers curtail their drilling activity in response to reduced commodity price expectations. As part of our long-term growth strategy, we continue to review complementary acquisitions as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. For additional discussion of our business strategy, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Acquisitions and Capital Spending
 
Since the completion of our initial public offering in February 2001, we have completed 35 acquisitions for total consideration of $497.0 million. Acquisitions of other oilfield service businesses have been an important aspect of our growth strategy and plans to increase shareholder value. Our acquisition strategy has primarily been focused in the well site services segment where we have expanded our geographic locations and our product and service offerings, especially in our rental tool business line. This growth strategy has allowed us to leverage our existing and acquired product and service offerings in new geographic locations. We have also made strategic acquisitions in offshore products, tubular services and in other well site services business lines.


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Capital spending since our initial public offering in February 2001 has totaled $857.1 million and has included both growth and maintenance capital expenditures in each of our businesses as follows: Accommodations — $402.8 million, Rental Tools — $193.4 million, Drilling and Other — $167.9 million, Offshore Products — $81.2 million, Tubular Services — $9.1 million and Corporate — $2.7 million.
 
In 2002 through 2004, we acquired 19 businesses for total consideration of $178.0 million. Each of the businesses acquired became part of our existing business segments and included rental tool companies, offshore products companies and product lines and a tubular distribution company.
 
In 2005, we completed nine acquisitions for total consideration of $158.6 million. In our well site services segment, we acquired a Wyoming based land drilling company, five related entities providing wellhead isolation equipment and services, and a Canadian manufacturer of work force accommodations. Our tubular services segment acquired a Texas based oil country tubular goods (OCTG) distributor, and our offshore products segment acquired a small product line.
 
In August 2006, we acquired three drilling rigs operating in West Texas for total consideration of $14.0 million. The rigs acquired, which are classified as part of our capital expenditures in 2006, were added to our existing West Texas drilling fleet in our drilling services business within the well site services segment.
 
In 2007, we acquired two rental tool businesses primarily providing well testing and flowback services and completion-related rental tools for total consideration of $112.8 million. The operations of these businesses have been included in the rental tools business within the well site services segment.
 
In 2008, we completed two acquisitions for total consideration of $29.9 million. In February 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., the owners of an accommodations lodge (Christina Lake Lodge) in the Conklin area of Alberta, Canada, for total consideration of $7.0 million. Christina Lake Lodge provides lodging and catering in the southern area of the oil sands region. The Christina Lake Lodge has been included in the accommodations business within the well site services segment since the date of acquisition. In February 2008, we also acquired a waterfront facility on the Houston ship channel for use in our offshore products segment for total consideration of $22.9 million. The new waterfront facility expanded our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities.
 
Workover Services Business Transaction
 
Effective March 1, 2006, we completed a transaction to combine our workover services business with Boots & Coots International Well Control, Inc. (AMEX: WEL) (Boots & Coots) in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.2 million. Our workover services business was part of our well site services segment prior to the combination. The closing of the transaction resulted in a non-cash pretax gain of $20.7 million.
 
As a result of the closing of the transaction, we initially owned 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction bear a fixed annual interest rate of 10% and mature on September 1, 2010. In connection with this transaction, we also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement. A shelf registration statement was finalized by Boots & Coots effective in the fourth quarter of 2006 and we sold shares in 2007 and 2008 as described below.
 
In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots common stock that it owned for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share, in the second quarter of 2007. After this sale of Boots & Coots shares and the sale of primary shares of stock directly by Boots & Coots in April 2007, our ownership interest in Boots & Coots was reduced to approximately 15%. The carrying value of the Company’s remaining investment in Boots & Coots common stock totaled $19.6 million as of December 31, 2007.
 
The Company sold an aggregate total of 11,512,137 shares of Boots & Coots common stock representing the remaining shares that it owned in a series of transactions during May, June and August of 2008. The sale of Boots & Coots common stock resulted in net proceeds of $27.4 million and a net after tax gain of $3.6 million, or


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approximately $0.07 per diluted share, in the twelve months ended December 31, 2008. The carrying value of the Company’s senior subordinated promissory notes receivable due from Boots & Coots was $21.2 million as of December 31, 2008 and is included in other non-current assets on the balance sheet. In February 2009, we received $21.2 million in cash from Boots & Coots in full payment of the senior subordinated promissory notes.
 
Our Industry
 
We operate in the oilfield services industry and provide a broad range of products and services to our customers through our offshore products, tubular services and well site 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 oil and natural gas exploration and development activities. Management estimates that approximately 55% to 60% of the Company’s revenues are dependent on North American natural gas drilling and completion activity with a significant amount of such revenues being derived from lower margin OCTG sales. As such, we estimate that our profitability is fairly evenly balanced between oil driven activity and natural gas driven activity. Demand for our products and services by our customers is highly sensitive to current and expected future oil and natural gas prices. See Note 14 to our Consolidated 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.
 
Our financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments. The current sustained declines in oil and gas prices, particularly in combination with the constrained capital and credit markets and overall economic downturn, has resulted in a decline in activity by customers in each of our segments during the first quarter of 2009. For additional information on how each of our segments have responded to declines in oil and natural gas prices, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Our Well Site Services businesses, which are significantly affected by the North American rig count, saw increasing activity from 2004 through 2006, had relatively flat year-over-year activity in 2007 and again saw an overall increase in activity for the year 2008, but saw declines beginning in the fourth quarter of 2008 which have continued into 2009. Acquisitions and capital expenditures made in this segment have created growth opportunities. In addition, increased activity supporting oil sands developments in northern Alberta, Canada by our work force accommodations, catering and logistics business has had a positive impact on this segment’s overall trends.
 
Our Offshore Products segment, which is more influenced by deepwater development activity and rig and vessel construction and repair, experienced decreased activity during 2004; however, backlog increased significantly from 2004 to 2008, which resulted in improved operating results during 2005, 2006, 2007 and in 2008. However, new order activity slowed in the latter part of 2008.
 
Our Tubular Services business is influenced by U.S. drilling activity similar to our Well Site Services and has historically been our most cyclical business segment. In addition, during 2005 and 2008, this segment’s margins were positively affected in a significant manner by increasing prices for steel products, including the OCTG we sell. Prices for steel products remained comparatively stable during 2006, declined in 2007 and then increased in 2008. Subsequent to December 31, 2008, OCTG prices have weakened.
 
Well Site Services
 
Overview
 
During the year ended December 31, 2008, we generated approximately 33% of our revenue and 52% of our operating income, before corporate charges, from our Well Site Services segment. Our well site services segment includes 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 and to accommodate personnel in remote locations. Our operations include land drilling services, work force accommodations and associated services and rental tools. We use our fleet of drilling rigs, rental equipment and work force accommodation facilities to serve our customers at well sites and project development locations. Our products and services are used in both onshore and offshore applications throughout the exploration, development and production phases of a well’s life. Additionally, our work force accommodations and


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associated services are employed to support work forces in the oil sands and a variety of mining and related natural resource applications as well as forest fire fighting and disaster relief efforts.
 
Well Site Services Market
 
Demand for our drilling rigs, rental equipment and work force accommodations and associated services has historically been tied to the level of activity by oil and gas explorationists and producers. The primary driver for this activity is the price of oil and natural gas. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices. Demand for our workforce accommodations business has grown in recent years due to the increasing demand for accommodations to support workers in the oil sands region of Canada. However, full utilization of additional capacity as a result of our current and future expansions of our accommodations facilities will largely depend on continued oil sands developments. Because costs for production from oil sands may be substantially higher than costs to produce conventional crude oil, the recent decline in crude oil prices has made certain oil sands projects less profitable or uneconomic. If crude oil prices remain at their current levels or decline further, oil sands producers may cancel or delay plans to expand their facilities, as some oil sands producers have already done.
 
Products and Services
 
Drilling Services.  Our drilling services business is located in the United States and provides land drilling services for shallow to medium depth wells ranging from 1,500 to 12,500 feet. Drilling services are typically used during the exploration and development stages of a field. We have a total of 36 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 75,000 to 500,000 pounds, 12 of which were fabricated and/or assembled in our Odessa, Texas facility with components purchased from specialty vendors. Twenty-two of these drilling rigs are based in Odessa, Texas, ten are based in the Rocky Mountains region and four are based in Wooster, Ohio. Utilization increased from an average of 79.3% in 2007 to an average of 82.4% in 2008. On December 31, 2008, 61.1% of our rigs, or 22 rigs, were working or under contract. One additional rig was under construction in our facility in Odessa, Texas at December 31, 2008. Utilization has decreased in early 2009, and has been in the range of 35% to 45%.
 
We market our drilling services directly to a diverse customer base, consisting of major, independent and private oil and gas companies. Our largest customers in drilling services in 2008 included Apache Corporation and Occidental Petroleum Corporation. We contract on both footage and dayrate basis. Under a daywork drilling contract, the customer pays for certain costs that the Company would normally provide when drilling on a footage basis, and the customer assumes more risk than on a footage basis. Depending on market conditions and availability of drilling rigs, we will see changes in pricing, utilization and contract terms. The land drilling business is highly fragmented and our competition consists of a small number of large companies and many smaller companies.
 
Rental Equipment.  Our rental equipment business provides a wide range of products and services for use in the offshore and onshore oil and gas industry, including:
 
  •  wireline and coiled tubing pressure control equipment;
 
  •  wellhead isolation equipment;
 
  •  pipe recovery systems;
 
  •  thru-tubing fishing services;
 
  •  hydraulic chokes and manifolds;
 
  •  blow out preventers;
 
  •  well testing equipment, including separators and line heaters;
 
  •  gravel pack operations on well bores; and
 
  •  surface control equipment and down-hole tools utilized by coiled tubing operators.


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Our rental equipment is primarily used during the completion and production stages of a well. As of December 31, 2008, we provided rental equipment at 72 distribution points throughout the United States, Canada, Mexico and Argentina. We are currently combining some of these distribution points in key markets where opportunities exist to streamline operations and market our equipment more effectively. We provide rental equipment on a daily rental basis with rates varying depending on the type of equipment and the length of time rented. In certain operations, we also provide service personnel in connection with the equipment rental. We own patents covering some of our rental tools, particularly, in our wellhead isolation equipment product line. Our customers in the rental equipment business include major, independent and private oil and gas companies and other large oilfield service companies. Competition in the rental tool business is widespread and includes many smaller companies, although we do compete with a small number of the larger oilfield service companies, who are also our customers for certain products and services.
 
Workforce Accommodations, Catering, Logistics and Modular Building Construction.  We are one of North America’s largest providers of integrated services providing accommodations for people working in remote locations. Our scalable modular facilities provide temporary and permanent workforce accommodations where traditional hotels and infrastructure are not accessible or cost effective. Once the facilities are deployed in the field, we also provide catering and food services, housekeeping, laundry, facility management, water and wastewater treatment, power generation, communications and redeployment logistics.
 
In addition to our large-scale lodge facilities, we offer a broad range of semi-permanent and mobile options to house workers in remote regions. Our fleet of temporary camps is designed to be deployed on short notice and can be relocated as a project site moves. Our temporary camps range in size from a 25 person drilling camp to a 2,000 person construction camp.
 
We own two manufacturing plants which specialize in the design, engineering, production, transportation and installation of a variety of portable modular buildings. We manufacture facilities to suit the climate, terrain and population of a specific project site.
 
Our workforce accommodations business is focused primarily in western and northern Canada, but also operates in the U.S. Rocky Mountain corridor (Wyoming, Colorado, Utah), Fayetteville Shale region of Arkansas and offshore locations in the Gulf of Mexico. In the past, we have also served companies operating in international markets including the Middle East, Europe, Asia and South America.
 
Our customers operate in a diverse mix of industries including primarily oil sands mining and development, and drilling, exploration and extraction of oil and gas. We also operate in other industries, but to a lesser extent, including pipeline construction, mining, forestry, humanitarian aid and disaster relief, and support for military operations. Our largest customers in the workforce accommodations market in 2008 were Suncor Energy, Inc. and Albian Sands Energy, Inc. Our primary competitors in Canada include Aramark Corporation, Compass Group PLC, ATCO Structures Limited, Black Diamond Income Fund and Horizon North Logistics, Inc.
 
To a significant extent, the Company’s recent capital expenditures have focused on opportunities in the oil sands region in northern Alberta. Since the beginning of 2005, we have spent $322.8 million, or 46.1%, of our total consolidated capital expenditures in our Canadian accommodations business. Most of these capital investments have been in support of oil sands developments, both for initial construction phases and ongoing operations. In addition, as conventional oil and gas drilling has decreased, we have shifted certain accommodations assets, formerly used in support of conventional drilling and mining activities, to support demand in the oil sands. Oil sands related accommodations revenues have increased from 32.9% of total accommodations revenues in 2005 to 67.7% in 2008.
 
Since mid year 2006, we have installed over 5,300 rooms in four of our major lodge properties supporting oil sands activities in northern Alberta. Our growth plan for this area of our business includes the expansion of these properties where we believe there is durable long-term demand. As of December 31, 2008, these company-owned properties include PTI Beaver River Executive Lodge (732 rooms), PTI Athabasca Lodge (1,537 rooms), PTI Wapasu Creek Lodge (2,702 rooms) and PTI Conklin Lodge (376 rooms). We are currently expanding the capacity of our PTI Wapasu Creek Lodge to 2,991 rooms in 2009.


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Offshore Products
 
Overview
 
During the year ended December 31, 2008, we generated approximately 18% of our revenue and 22% 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. In addition, we have other lower margin products and services such as fabrication and inspection services. 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; Singapore and Thailand 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 and vessel construction. Demand for oil and gas and related drilling and production in offshore areas throughout the world, particularly in deeper water, will drive spending on these activities.
 
The upgrade of existing rigs to equip them with the capability to drill in deeper water and withstand harsh operating conditions, 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 in part on the industry’s 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 for risers 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 (FPSO) 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;
 
  •  conductor casing connections and pipe;
 
  •  drilling riser repair services;
 
  •  blowout preventer 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®, 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® are flexible bearings that permit the controlled movement of riser pipes or tension leg platform tethers under high tension and pressure. They are


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used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water areas. Drilling riser systems 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® 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 facilities, are a significant means of producing oil and gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. 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® 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 sections 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. Our FlexJoints® are also used to attach the steel catenary risers to a Spar, FPSO or tension leg platform and for use on import or export risers.
 
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:
 
  •  pipeline end manifolds, pipeline end terminals;
 
  •  midline tie-in sleds;
 
  •  forged steel Y-shaped connectors for joining two pipelines into one;
 
  •  pressure-balanced safety joints for protecting pipelines and related equipment 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


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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 revenue to us.
 
BOP Stack Assembly, Integration, Testing and Repair Services.  We design and fabricate lifting and protection frames and offer system integration of blow-out preventer 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 preventer 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® hydraulic system. The Hydra-Lok® tool, which has been successfully used at depths of 3,000 feet, does not require diver intervention or guide lines.
 
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;
 
  •  sound and vibration isolation equipment for the U.S. Navy submarine fleet;
 
  •  metal-elastomeric FlexJoints® used in a variety of naval and marine 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 $362.1 million at December 31, 2008, compared to $362.2 million at December 31, 2007 and $349.3 million at December 31, 2006. We expect in excess of 85% of our backlog at December 31, 2008 to be completed in 2009. Our offshore products backlog consists of firm customer purchase orders for which contractual commitments 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, Azerbaijan, the North Sea, Brazil and Southeast Asia. We are currently expanding our capabilities in Southeast Asia by constructing a new facility in Singapore.
 
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.
 
Tubular Services
 
Overview
 
During the year ended December 31, 2008, we generated approximately 50% of our revenue and 26% of our operating income, before corporate charges, from our tubular services segment. Through this segment, we distribute


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OCTG and provide associated OCTG finishing and logistics services to the oil and gas industry. OCTG 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 management services; and
 
  •  offer e-commerce pricing, ordering, tracking and financial reporting capabilities.
 
We serve a customer base ranging from major oil and gas companies to small independents. Through our key relationships with more than 20 domestic and foreign manufacturers and related service providers and suppliers 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 focused in the United States. We purchase tubular goods from a variety of sources. However, during 2008, we purchased from a single domestic supplier 58% of the total tubular goods we purchased and from three domestic suppliers approximately 75% of such tubular goods. Since the fourth quarter of 2008, we have reduced our forward purchase commitments for OCTG considering the decline in drilling activity.
 
OCTG Market
 
Our tubular services segment primarily distributes casing and tubing. Casing forms the structural wall in oil and gas wells to provide support, control pressure and prevent caving during drilling operations. Casing is also 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 aggregate footage of wells drilled onshore and offshore in the United States. The OCTG market is also affected by the level of inventories maintained by manufacturers, distributors and end users. Inventory on the ground, when at high levels, can cause tubular sales to lag a rig count increase due to inventory destocking. 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 eight offices and facilities located near areas of oil and gas exploration and development activity. We have distribution relationships with most major domestic and certain international steel mills.
 
In this business, inventory management is critical to our success. We maintain on-the-ground inventory in approximately 60 yards located in the United States, giving us the flexibility to fill customer orders from our own stock or directly from the manufacturer. We have a proprietary inventory management system, designed specifically for the OCTG industry, which enables us to track our product shipments.
 
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, has a rail spur and 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.


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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.
 
Other Facilities.  We also offer tubular services at our facilities in Midland and Godley, Texas and Searcy, Arkansas. Our Midland, Texas facility covers approximately 60 acres and has more than 400 pipe racks. Our Godley, Texas facility, which services the Barnett shale area, has approximately 60 pipe racks on approximately 27 developed acres and is serviced by a rail spur. Independent third party inspection companies operate within each of these facilities.
 
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 or program 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 a small percentage for export worldwide.
 
Customers, Suppliers and Competitors
 
Our largest end-user customer in the tubular distribution market in 2008 was Chesapeake Energy Corporation. Our largest suppliers were U.S. Steel Group and Tenaris Global Services USA Corporation. Although we have a leading market share position in tubular services distribution, the market is highly fragmented. Our main competitors in tubular distribution are Premier Pipe L.P., McJunkin Red Man Corporation (formerly Red Man Pipe & Supply Co., Inc.), Bourland & Leverich Supply Company, L.C. and Pipeco Services.
 
Seasonality of Operations
 
Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian work force accommodations, catering and logistics operations is conducted during the winter months when the winter freeze in remote regions is required for 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 quarter. 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. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. 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. For example, during 2005, a significant disruption occurred in oil and gas drilling and production operations in the U.S. Gulf of Mexico due to damage inflicted by Hurricanes Katrina and Rita and, during 2008, from Hurricane Ike.
 
Employees
 
As of December 31, 2008, we had 6,983 full-time employees, 25% of whom are in our offshore products segment, 72% of whom are in our well site services segment, 2% of whom are in our tubular services segment and 1% of whom are in our corporate headquarters. We are party to collective bargaining agreements covering 1,150 employees located in Canada, the United Kingdom and Argentina as of December 31, 2008. We believe relations with our employees are good.


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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 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, modification or cessation of operations, 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. However, there can be no assurance that substantial costs for compliance or penalties for non-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 or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities that we cannot currently quantify.
 
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.
 
With regard to our U.S. operations, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also know as 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 transported, 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 in the United States 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


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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 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.
 
In the course of our domestic operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.
 
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 domestic 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 in the United States 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.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, many foreign nations, including Canada, have agreed to limit emissions of these gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” In December 2002, Canada ratified the Kyoto Protocol. The Kyoto Protocol requires Canada to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. The implementation of the Kyoto Protocol in Canada is expected to affect the operation of all industries in Canada, including the oilfield service industry and its customers in the oil and natural gas industry. On April 26, 2007, the Government of Canada released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the Action Plan) also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and strengthens energy standards for a number of products. On March 10, 2008, the Government of Canada released details of the Action Plan’s regulatory framework, which includes a requirement that all covered industrial sectors, including upstream oil and gas facilities meeting certain threshold requirement, reduce their emissions from 2006 levels by 18% by 2010. The Government of Canada is in the process of developing regulations to implement the Action Plan.
 
The Government of Canada and the Province of Alberta also released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which made several recommendations, including: (i) incorporating a role for carbon capture and storage in meeting emissions reductions goals; (ii) allocating new funding for carbon capture and storage projects through a competitive process; and (iii) clarifying regulatory jurisdiction and long-term liability issues associated with carbon capture and storage.
 
As precise details of the implementation of the Action Plan have not yet been finalized, the effect on our operations in Canada cannot be determined at this time. It is possible that already stringent air emissions regulations


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applicable to our operations and the operations of our customers in Canada will be replaced with even stricter requirements prior to 2012. These requirements could increase our and our customers’ cost of doing business, reduce the demand for the oil and gas our customers produce, and thus have an adverse effect on the demand for our products and services.
 
Although the United States is not participating in the Kyoto Protocol, the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. In 2007, the Western Climate Initiative, which is comprised of a number of Western states, including the state of Utah, and Canadian provinces issued a greenhouse gas reduction goal statement in which it announced a goal to collectively reduce regional greenhouse gas emissions to 15% below 2005 levels by 2020. Additionally, the state of New Mexico recently enacted greenhouse gas emissions reporting requirements.
 
Depending on the particular program, our customers could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from their operations or from combustion of fuels (such as oil or natural gas) they produce, prepare an inventory of their emissions, or pay a tax on their greenhouse gas emissions. A stringent greenhouse gas control program could have an adverse effect on our customers’ cost of doing business and could reduce demand for the oil and gas they produce and thus have an adverse affect on the demand for our products and services.
 
Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. In July 2008, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for oil and gas and thus demand for our products and services.
 
Our operations outside of the United States are potentially subject to similar foreign governmental controls relating to protection of the environment. We believe that, to date, our operations outside of the United States have been in substantial compliance with existing requirements of these foreign governmental bodies and that such compliance has not had a material adverse effect on our operations. However, this trend of compliance may not continue in the future or the cost of such compliance may become material. For instance, any future restrictions on emissions of greenhouse gases that are imposed in foreign countries in which we operate, such as in Canada, pursuant to the Kyoto Protocol or other locally enforceable requirements could adversely affect demand for our services.
 
Item 1A.   Risk Factors
 
Our Business is Subject to a Number of Economic Risks
 
As widely reported, financial markets worldwide have been experiencing extreme disruption in recent months, including, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others. Governments have taken unprecedented actions intended to address extreme market conditions that include severely restricted credit and


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declines in real estate values. While, currently, these conditions have not impaired our ability to finance our operations, there can be no assurance that there will not be a further deterioration in financial markets. The global economy has slowed and there has been substantial uncertainty in the capital markets. These economic developments affect businesses such as ours in a number of ways. The current tightening of credit in financial markets and slowing economy adversely affects the ability of customers and suppliers to obtain financing for significant operations, has resulted in lower demand for our products and services, and could result in a decrease in or cancellation of orders included in our backlog and adversely affect the collectability of receivables. Additionally, the current tightening of credit in financial markets coupled with the slowing economy could negatively impact our ability to grow and cost of capital. Our business is also adversely affected when energy demand is lowered due to decreases in the general level of economic activity, such as decreases in business and consumer spending and travel, which results in lower energy prices, and therefore, less oilfield activity and lower demand for our products and services. These conditions could have an adverse effect on our operating results and the ability to recover our assets at their stated values. Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Strengthening of the rate of exchange for the U.S. Dollar against certain major currencies such as the Euro, the British Pound and the Canadian Dollar and other currencies could also adversely affect our results. Most of these events have occurred to some degree thus far in the current recession. We are unable to predict the likely duration and severity of the current disruption in financial markets and adverse economic conditions in the U.S. and other countries or their ultimate impact on our Company.
 
Decreased oil and gas industry expenditure levels will adversely affect our results of operations.
 
Demand for our products and services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. If our customers’ 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. Prices for oil and natural gas have declined precipitously recently and are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other factors that are beyond our control. A sudden or long term decline in product pricing similar to what we are experiencing currently will materially adversely affect our results of operations. Any prolonged reduction in oil and natural gas prices will depress levels of exploration, development, and production activity, often reflected as reductions in rig counts. We have experienced a significant decline in utilization of our drilling rigs in late 2008 and thus far in 2009. Oil and gas prices have also declined from record highs reached in 2008. We currently expect that decreased energy prices and drilling will also negatively impact our other well site services businesses and tubular services business in 2009. Such lower activity levels are expected to materially adversely affect our revenue and profitability and could result in an impairment of our asset carrying values. Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil and gas. Many factors affect the supply and demand for oil and gas and therefore influence product prices, including:
 
  •  the level of drilling activity;
 
  •  the level of production;
 
  •  the levels of oil and gas inventories;
 
  •  depletion rates;
 
  •  the worldwide demand for oil and gas;
 
  •  the expected cost of developing new reserves;
 
  •  delays in major offshore and onshore oil and gas field development timetables;
 
  •  the actual cost of finding and 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;


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  •  the availability of transportation infrastructure, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
 
  •  global weather conditions and natural disasters;
 
  •  worldwide economic activity including growth in underdeveloped countries, including China and India;
 
  •  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 and government policies which could nationalize or expropriate oil and gas exploration, production, refining or transportation assets;
 
  •  the level of oil and gas production by non-OPEC countries;
 
  •  the impact of armed hostilities involving one or more oil producing nations;
 
  •  rapid technological change and the timing and extent of alternative energy sources, including liquefied natural gas (LNG) or other alternative fuels;
 
  •  environmental regulation; and
 
  •  domestic and foreign tax policies.
 
Our business may be adversely affected by extended periods of low oil prices or unsuccessful exploration results may decrease deepwater exploration and production activity or oil sands development and production in Canada.
 
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. The economic analyses conducted by exploration and production companies for very large oil sands developments are similar to those performed for deepwater projects with respect to oil price assumptions. If crude oil prices remain at their current levels or decline further, oil sands producers may cancel or delay plans to expand their facilities, which would adversely impact demand for our well site services segment. For example, in November 2008, one of our customers announced the suspension of all activities associated with a development project in the Canadian oil sands during 2009 and amended its contract with us relating to the construction and rental of a 1,016 bed facility. For more information, see Note 17 to the Consolidated Financial Statements included in this Annual Report on Form 10-K. Perceptions of longer-term lower oil prices by these companies can reduce or defer major expenditures given the long-term nature of many large scale development projects, which could adversely affect our revenues and profitability in our offshore products segment and our well site services segment.
 
Because the oil and gas industry is cyclical, our operating results may fluctuate.
 
Oil prices, which have dropped precipitously in the last six months after reaching historical highs, 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 expect to experience in 2009, significant fluctuations in operating results based on these changes.
 
The cyclical nature of our business and a severe prolonged downturn could negatively affect the value of our goodwill.
 
As of December 31, 2008, goodwill represented approximately 13% 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, some of which are beyond our control, indicate that the carrying amount will not be recoverable. In the fourth quarter of 2008, we recognized an impairment of a portion of our goodwill totaling $85.6 million as a result of several factors affecting our tubular services and drilling


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reporting units. It is possible that we could recognize additional goodwill impairment charges if, among other factors:
 
  •  global economic conditions deteriorate further than those conditions that existed at December 31, 2008;
 
  •  the outlook for future profits and cash flow for any of our reporting units deteriorate as the result of many possible factors, including, but not limited to, increased or unanticipated competition, further reductions in customer capital spending plans, loss of key personnel, adverse legal or regulatory judgment(s), future operating losses at a reporting unit, downward forecast revisions, or restructuring plans;
 
  •  costs of equity or debt capital increase further; or
 
  •  valuations for comparable public companies or comparable acquisition valuations deteriorate further.
 
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 end users in the United States, our results of operations could be adversely impacted.
 
Lower-cost tubular goods from a number of foreign countries are imported into the U.S. tubular goods market. If the level of imported lower-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 or if prices and margins are driven down by increased supplies of tubular goods. 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 through distributors. If customers were to purchase tubular goods directly from steel mills, our results of operations could be adversely impacted.
 
If we were to lose a significant supplier of our tubular goods, we could be adversely affected.
 
During 2008, we purchased from a single domestic supplier approximately 58% of the total tubular goods we distributed and purchased from three domestic suppliers approximately 75% of such tubular goods. We do not have contracts with all 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 adversely affected. If the extent of the loss or interruption were sufficiently large, the impact on us would be material.
 
Our operations may suffer due to increased industry-wide capacity of certain types of equipment or assets.
 
The demand for and pricing of certain types of our assets and equipment, particularly our drilling rigs and some of our rental tool assets, is subject to the overall availability of such assets in the marketplace. If demand for our assets were to decrease, or to the extent that we and our competitors increase our fleets in excess of current demand, we may encounter decreased pricing or utilization for our assets and services, which could adversely impact our operations and profits. Currently, we are experiencing certain of these effects as demand has declined and pricing pressures have increased.
 
In addition, we have significantly increased our accommodations capacity in the oil sands region over the past four years based on our expectation for current and future customer demand for accommodations in the area. Should our customers build their own facilities to meet their accommodations needs or our competitors likewise increase their available accommodations, demand for our accommodations could decrease, negatively impacting the profitability of our well site services segment.


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Development of permanent infrastructure in the oil sands region could negatively impact our accommodations business.
 
Our accommodations business specializes in providing housing and personnel logistics for work forces in remote areas which lack the infrastructure typically available in nearby towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of Alberta, Canada, the demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.
 
We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the United States.
 
A portion of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 20% (6.4% excluding Canada) of our consolidated revenue in the year ended December 31, 2008. Risks associated with our operations in foreign areas include, but are not limited to:
 
  •  war and civil disturbances or other risks that may limit or disrupt markets;
 
  •  expropriation, confiscation or nationalization of assets;
 
  •  renegotiation or nullification of existing contracts;
 
  •  foreign exchange restrictions;
 
  •  foreign currency fluctuations;
 
  •  foreign taxation;
 
  •  the inability to repatriate earnings or capital;
 
  •  changing political conditions;
 
  •  changing foreign and domestic monetary policies;
 
  •  social, political, military and economic situations in foreign areas where we do business and the possibilities of war, other armed conflict or terrorist attacks; and
 
  •  regional economic downturns.
 
Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete.
 
Our international business operations also include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to United States laws and regulations, such as the Foreign Corrupt Practices Act, can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that United States law and regulations prohibit us from using. For example, our non-U.S. competitors are not subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally owned oil companies in order to obtain or retain any business or other advantage. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.
 
Violations of these laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
 
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


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ability to expand our operations depends in part on our ability to increase our skilled labor force. During periods of increased activity, the demand for skilled workers is high, and the supply is limited. Through 2008, we have experienced high demand and increased wages for labor forces serving our well site services segment, notably in our accommodations business in Canada. We saw significant increases in the wages paid by competing employers resulting in increases in the wage rates that we paid. When these events occur, our cost structure increases and our growth potential could be impaired. Recently, with the decline in activity in the oil field service and manufacturing businesses generally, we are seeing less pressure on wages and improvement in our ability to attract and retain employees.
 
Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.
 
Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders.
 
We expect to gain certain business, financial and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize the benefits of that. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition. Additional risks we could face in connection with acquisitions include:
 
  •  retaining key employees of acquired businesses;
 
  •  retaining and attracting new customers of acquired businesses;
 
  •  increased administrative burden;
 
  •  developing our sales and marketing capabilities;
 
  •  managing our growth effectively;
 
  •  potential impairment resulting from the overpayment for an acquisition;
 
  •  integrating operations;
 
  •  operating a new line of business; and
 
  •  increased logistical problems common to large, expansive operations.
 
Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.
 
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.
 
All of our operations, especially our drilling and offshore products businesses, are significantly affected by stringent and complex foreign, federal, provincial, 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 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 are subject to change in the future, possibly resulting in more stringent requirements. If existing


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regulatory requirements or enforcement policies change or are more stringently enforced, 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 be exposed to certain regulatory and financial risks related to climate change.
 
Climate change is receiving ever increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
 
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of foreign, U.S. federal, regional and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
 
  •  result in increased costs associated with our operations and our customers’ operations;
 
  •  increase other costs to our business;
 
  •  impact overall drilling activity in the areas in which we operate; and
 
  •  reduce the demand for our services.
 
Any adoption by U.S. federal or state governments mandating a substantial reduction in greenhouse gas emissions and implementation of the Kyoto Protocol by the Government of Canada could have far-reaching and significant impacts on the energy industry. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our services. See Item 1. Government Regulation for a more detailed description of our climate-change related risks.
 
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;
 
  •  the counterparties to our insurance contracts may pose credit risks; and
 
  •  we may incur losses from interruption of our business that exceed our insurance coverage.
 
Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position.


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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.
 
The markets in which we operate are highly competitive and certain of them have relatively few barriers to entry. The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. In some of our business segments, we compete with the oil and gas industry’s largest oilfield service providers. These large national and multi-national companies have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
 
Our concentration of customers in one industry may impact overall exposure to credit risk.
 
Substantially all of our customers operate in the energy industry. This concentration of customers in one industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.
 
Our common stock price has been volatile.
 
The market price of common stock of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past, and we expect it to continue to remain highly volatile.
 
We may assume contractual risk in developing, manufacturing and delivering products in our offshore products business segment.
 
Many of our products from our offshore products segment are ordered by customers under frame agreements or project specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. In addition, the final delivered products may include customer and third party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.
 
In certain cases these orders include new technology or unspecified design elements. In some cases we may not be fully or properly compensated for the cost to develop and design the final products, negatively impacting our profitability on the projects. In addition, our customers, in many cases, request changes to the original design or bid specifications for which we may not be fully or properly compensated.
 
As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs and any gross profit realized on these fixed-


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price contracts may vary from the initially expected contract economics. There is inherent risk in the estimation process and including significant unforeseen technical and logistical challenges or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices (including the price of steel) through increased pricing. Depending on the size of a project, variations from estimated contract performance could have a significant impact on our operating results.
 
Our backlog is subject to unexpected adjustments and cancellations and is, therefore, an uncertain indicator of our future revenues and earnings.
 
The revenues projected in our backlog may not be realized or, if realized, may not result in profits. Because of potential changes in the scope or schedule of our customers’ projects, we cannot predict with certainty when or if backlog will be realized. In addition, even where a project proceeds as scheduled, it is possible that contracted parties may default and fail to pay amounts owed to us. Material delays, cancellations or payment defaults could materially affect our financial condition, results of operations and cash flows.
 
Reductions in our backlog due to cancellation by a customer or for other reasons would adversely affect, potentially to a material extent, the revenues and earnings we actually receive from contracts included in our backlog. Some of the contracts in our backlog are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. We typically have no contractual right upon cancellation to the total revenues reflected in our backlog. If we experience significant project terminations, suspensions or scope adjustments to contracts reflected in our backlog, our financial condition, results of operations and cash flows may be adversely impacted.
 
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, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian work force accommodations, catering and logistics operations is conducted during the winter months when the winter freeze in remote regions is required for 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. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. 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. For example, during 2005, a significant disruption occurred in oil and gas drilling and production operations in the U.S. Gulf of Mexico due to damage inflicted by Hurricanes Katrina and Rita and, during 2008, from Hurricane Ike.
 
Our oilfield operations involve a variety of operating hazards and risks that could cause losses.
 
Our operations are subject to the hazards inherent in the oilfield business. These include, but are not limited to, equipment defects, blowouts, explosions, fires, collisions, capsizing and severe weather conditions. These hazards could result in personal injury and loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage and suspension of operations. We may incur substantial liabilities or losses as a result of these hazards as part of our ongoing business operations, we may agree to indemnify our customers against specific risks and liabilities. While we maintain insurance protection against some of these risks, and seek to obtain indemnity agreements from our customers requiring the customers to hold us harmless from some of these risks, our insurance and contractual indemnity protection may not be sufficient or effective to protect us under all circumstances or against all risks. The occurrence of a significant event not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition.


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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® technology and intervention tools utilized in the completion or workover of oil and gas wells. The market success of our technologies will depend, in part, on our ability to obtain and enforce our proprietary rights in these technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented or challenged. If any of our patents or other intellectual property rights are determined to be invalid or unenforceable, or if a court limits the scope of claims in a patent or fails to recognize our trade secret rights, our competitive advantages could be significantly reduced in the relevant technology, allowing competition for our customer base to increase. 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. In addition, competitors or customers may develop new technology which addresses similar or improved solutions to our existing technology. Should our technology, particularly in offshore products or in our rental tool business, become the less attractive solution, our operations and profitability would be negatively impacted.
 
Loss of key members of our management could adversely affect our business.
 
We depend on the continued employment and performance of 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.
 
We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonpayment and nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.
 
Risks of nonpayment and nonperformance by our counterparties are a concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and insurers. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In connection with the recent economic downturn, commodity prices have declined sharply, and the credit markets and availability of credit have been constrained. Additionally, many of our customers’ equity values have declined substantially. The combination of lower cash flow due to commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of available debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any increase in the nonpayment and nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.


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During periods of strong demand, we may be unable to obtain critical project materials on a timely basis.
 
Our operations depend on our ability to procure on a timely basis certain project materials, such as forgings, to complete projects in an efficient manner. Our inability to procure critical materials during times of strong demand could have a material adverse effect on our business and operations.
 
Employee and customer labor problems could adversely affect us.
 
We are party to collective bargaining agreements covering 1,074 employees in Canada, 60 employees in the United Kingdom and 16 employees in Argentina. In addition, our accommodations facilities serving oil sands development work in Northern Alberta, Canada house both union and non-union customer employees. We have not experienced strikes, work stoppages or other slowdowns in the recent past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business, financial condition and results of operations.
 
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.
 
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.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
The following table presents information about our principal properties and facilities. For a discussion about how each of our business segments utilizes its respective properties, please see “Item 1. Business.” Except as indicated below, we own all of these properties or facilities.
 
             
    Approximate
     
    Square
     
Location
  Footage/Acreage     Description
 
United States:
           
Houston, Texas (lease)
    15,829     Principal executive offices
Arlington, Texas
    11,264     Offshore products business office
Arlington, Texas
    36,770     Offshore products business office and warehouse
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)
    52,000     Offshore products business office
Houston, Texas
    25 acres     Offshore products manufacturing facility and yard
Houston, Texas
    22 acres     Offshore products manufacturing facility and yard
Lampasas, Texas
    48,500     Molding facility for offshore products
Lampasas, Texas (lease)
    20,000     Warehouse for offshore products
Tulsa, Oklahoma
    74,600     Molding facility for offshore products
Tulsa, Oklahoma (lease)
    14,000     Molding facility for offshore products
Houma, Louisiana
    40 acres     Offshore products manufacturing facility and yard
Houma, Louisiana (lease)
    20,000     Offshore products manufacturing facility and yard
Houston, Texas (lease)
    9,945     Tubular services business office
Tulsa, Oklahoma (lease)
    11,955     Tubular services business office
Midland, Texas
    60 acres     Tubular yard
Godley, Texas
    31 acres     Tubular yard


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    Approximate
     
    Square
     
Location
  Footage/Acreage     Description
 
Crosby, Texas
    109 acres     Tubular yard
Searcy, Arkansas
    14 acres     Tubular yard
Belle Chasse, Louisiana (own and lease)
    427,020     Accommodations manufacturing facility and yard for well site services
Odessa, Texas
    22 acres     Office and warehouse in support of drilling operations for well site services
Wooster, Ohio (lease)
    12,400     Office and warehouse in support of drilling operations
Casper, Wyoming
    7 acres     Office, shop and yard in support of drilling operations
Billings, Montana (lease)
    7 acres     Office, shop and yard in support of drilling operations
Alvin, Texas
    36,150     Rental tool warehouse for well site services
Houston, Texas
    60,000     Rental tool warehouse for well site services
Monahans, Texas (lease)
    15 acres     Rental tool warehouse, shop and office for well site services
Oklahoma City, Oklahoma
    4 acres     Rental tool warehouse, shop and office for well site services
Broussard, Louisiana
    18,875     Rental tool warehouse for well site services
Canada:
           
Nisku, Alberta
    8.58 acres     Accommodations manufacturing facility 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
Grimshaw, Alberta (lease)
    20 acres     Accommodations equipment yard for well site services
Edmonton, Alberta
    33 acres     Accommodations manufacturing facility for well site services
Edmonton, Alberta (lease)
    72,456     Accommodations office and warehouse for well site services
Edmonton, Alberta (lease)
    16,130     Accommodations office for well site services
Fort McMurray, Alberta (lease)
    128 acres     Accommodations facility for well site services
Fort McMurray, Alberta (lease)
    80 acres     Accommodations facility for well site services
Fort McMurray, Alberta (lease)
    135 acres     Accommodations facility for well site services
Fort McMurray, Alberta
    45 acres     Accommodations facility for well site services
Other International:
           
Red Deer, Alberta
    35,000     Rental tool business office for well site services site services
Aberdeen, Scotland (lease)
    15 acres     Offshore products manufacturing facility and yard
Bathgate, Scotland
    3 acres     Offshore products manufacturing facility and yard
             
Barrow-in-Furness, England (own and lease)
    162,482     Offshore products service facility and yard
Singapore (lease)
    141,747     Offshore products manufacturing facility
Macae, Brazil (lease)
    6 acres     Offshore products manufacturing facility and yard
Rayong Province, Thailand (lease)
    28,000     Offshore products service facility
 
We have six tubular sales offices and a total of 72 rental tool supply and distribution points throughout the United States, Canada, Mexico and Argentina. Most of these office locations are leased and 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 indemnity or 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 2008.

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PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 
Common Stock Information
 
Our authorized common stock consists of 200,000,000 shares of common stock. There were 49,501,436 shares of common stock outstanding as of February 11, 2009, including 201,757 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 Agreement, 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 11, 2009 was 36. Our common stock is traded on the New York Stock Exchange under the ticker symbol OIS. The closing price of our common stock on February 11, 2009 was $18.40 per share.
 
The following table sets forth the range of high and low sales prices of our common stock.
 
                 
    Sales Price  
    High     Low  
 
2007:
               
First Quarter
    32.65       26.92  
Second Quarter
    42.45       31.66  
Third Quarter
    48.72       36.22  
Fourth Quarter
    50.98       30.36  
2008:
               
First Quarter
    45.88       30.94  
Second Quarter
    64.37       44.42  
Third Quarter
    64.84       32.39  
Fourth Quarter
    35.35       14.72  
2009:
               
First Quarter (through February 11, 2009)
    22.50       17.00  
 
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. 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.


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PERFORMANCE GRAPH
 
The following performance graph and chart compare the cumulative total stockholder return on the Company’s common stock to the cumulative total return on the Standard & Poor’s 500 Stock Index and Philadelphia OSX Index, an index of oil and gas related companies which represent an industry composite of the Company’s peer group, for the period from December 31, 2003 to December 31, 2008. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2003 and assume the reinvestment of all dividends.
 
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Oil States International, Inc., The S&P 500 Index
And The PHLX Oil Service Sector Index
 
(PERFORMANCE GRAPH)
 
Oil States International — NYSE
 
                                                             
      Cumulative Total Return
      12/03     12/04     12/05     12/06     12/07     12/08
OIL STATES INTERNATIONAL, INC.
    $ 100.00       $ 138.38       $ 227.26       $ 231.21       $ 244.76       $ 134.07  
                                                             
S & P 500
      100.00         110.88         116.33         134.70         142.10         89.53  
                                                             
PHLX OIL SERVICE SECTOR (OSX)
      100.00         131.78         195.68         220.88         322.32         132.62  
                                                             
 
 
$100 invested on 12/31/03 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.
 
(1) This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any filing by us under the Securities Act of 1933, as amended (the Securities Act), or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
 
(2) The stock price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.
 
Copyright © 2009, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm


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Equity Compensation Plans
 
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
 
Unregistered Sales of Equity Securities and Use of Proceeds
 
None.
 
Purchases of Equity Securities by the Issuer and Affiliated Purchases
 
                                 
                Cumulative Total
       
                Number of Shares
    Approximate
 
                Purchased
    Dollar Value of Shares
 
          Average Price
    as Part of the
    Remaining to be Purchased
 
    Total Number of
    Paid
    Share Repurchase
    Under the Share Repurchase
 
Period
  Shares Purchased     per Share     Program 1     Program  
 
October 1, 2008 — October 31, 2008
                2,869,932     $ 65,459,901  
                                 
November 1, 2008 — November 30, 2008
    253,713     $ 19.30       3,123,645     $ 60,563,083  
                                 
December 1, 2008 — December 31, 2008
    38,699     $ 16.54       3,162,344     $ 59,923,188  
                                 
Total
    292,412     $ 18.93       3,162,344     $ 59,923,188  
                                 
 
 
(1) During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, we announced the authorization of an additional $50.0 million and the extension of the program to August 31, 2008. On January 11, 2008, an additional $50 million was approved for the repurchase program and the duration of the program was extended to December 31, 2009. Through February 12, 2009, we have repurchased 3,162,344 shares of our common stock for $90.1 million under the repurchase program, leaving $59.9 million available for future share repurchases.
 
Item 6.   Selected Financial Data
 
The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2008. The following data should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations


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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,  
    2008     2007     2006     2005     2004  
 
Statements of Operations Data:
                                       
Revenues
  $ 2,948,457     $ 2,088,235     $ 1,923,357     $ 1,531,636     $ 971,012  
Costs and Expenses:
                                       
Product costs, service and other costs
    2,234,974       1,602,213       1,467,988       1,206,187       774,638  
Selling, general and administrative
    143,080       118,421       107,216       84,672       64,810  
Depreciation and amortization
    102,604       70,703       54,340       46,704       35,988  
Impairment of goodwill
    85,630                          
Other operating expense (income)
    (1,586 )     (888 )     (4,124 )     (488 )     460  
                                         
Operating income
    383,755       297,786       297,937       194,561       95,116  
                                         
Interest expense
    (17,530 )     (17,988 )     (19,389 )     (13,903 )     (7,667 )
Interest income
    3,561       3,508       2,506       475       363  
Equity in earnings of unconsolidated affiliates
    4,035       3,350       7,148       1,276       361  
Gain on sale of workover services business and resulting equity investment
    6,160       12,774       11,250              
Other income (expense)
    (922 )     928       2,195       98       595  
                                         
Income before income taxes
    379,059       300,358       301,647       182,507       88,768  
Income tax expense(1)
    (156,349 )     (96,986 )     (104,013 )     (60,694 )     (29,406 )
                                         
Net income
  $ 222,710     $ 203,372     $ 197,634     $ 121,813     $ 59,362  
                                         
Net income per common share
                                       
Basic
  $ 4.49     $ 4.11     $ 3.99     $ 2.47     $ 1.20  
                                         
Diluted
  $ 4.33     $ 3.99     $ 3.89     $ 2.41     $ 1.19  
                                         
Average shares outstanding
                                       
Basic
    49,622       49,500       49,519       49,344       49,329  
                                         
Diluted
    51,414       50,911       50,773       50,479       50,027  
                                         
Other Data:
                                       
EBITDA, as defined(2)
  $ 495,632     $ 385,541     $ 372,870     $ 242,639     $ 132,060  
Capital expenditures, including capitalized interest
    247,384       239,633       129,591       83,392       60,041  
Acquisitions of businesses, net of cash acquired
    29,835       103,143       99       147,608       80,806  
Net cash provided by operating activities
    257,464       247,899       137,367       33,398       97,167  
Net cash used in investing activities, including capital expenditures
    (246,094 )     (310,836 )     (114,248 )     (229,881 )     (137,713 )
Net cash provided by (used in) financing activities
    (1,666 )     60,632       (11,201 )     195,269       38,816  


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    At December 31,  
    2008     2007     2006     2005     2004  
 
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 30,199     $ 30,592     $ 28,396     $ 15,298     $ 19,740  
Total current assets
    1,237,484       865,667       783,989       663,744       435,184  
Net property, plant and equipment
    695,338       586,910       358,716       310,452       227,343  
Total assets
    2,299,247       1,929,626       1,571,094       1,342,872       933,612  
Long-term debt and capital leases, excluding current portion
    474,948       487,102       391,729       402,109       173,887  
Total stockholders’ equity
    1,218,993       1,084,827       839,836       633,984       530,024  
 
 
(1) Our effective tax rate was lowered by our net operating loss carry forwards in certain of the periods presented and increased in 2008 by the impairment of non-deductible goodwill.
 
(2) 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 its ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing its operating performance with the 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 one of the primary measures to benchmark for the award of incentive compensation under its 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 (in thousands):
 
                                         
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
 
Net income
  $ 222,710     $ 203,372     $ 197,634     $ 121,813     $ 59,362  
Depreciation and amortization
    102,604       70,703       54,340       46,704       35,988  
Interest expense, net
    13,969       14,480       16,883       13,428       7,304  
Income taxes
    156,349       96,986       104,013       60,694       29,406  
                                         
EBITDA, as defined
  $ 495,632     $ 385,541     $ 372,870     $ 242,639     $ 132,060  
                                         
 
ITEM 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
You should read the following discussion and analysis together with our consolidated financial statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.
 
Overview
 
We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site 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. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices except for our accommodations activities supporting oil sands developments which we believe are more tied to the long-term outlook for crude oil prices. Our offshore products segment provides highly engineered and


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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 and subsea pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by global deepwater drilling and production activities, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales and gross margins of our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled and the level of OCTG inventory and pricing. Historically, tubular services’ gross margin expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services business segment, we provide land drilling services, work force accommodations and associated services and rental tools. Demand for our drilling services is driven by land drilling activity in Texas, New Mexico, Ohio and in the Rocky Mountains area in the U.S. Our rental tools and services depend primarily upon the level of drilling, completion and workover activity in North America. Our accommodations business is conducted principally in Canada and its activity levels are currently being driven primarily by oil sands development activities in northern Alberta.
 
We have a diversified product and service offering which has exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the drilling rig count in the United States and Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.
 
                                         
    Average Rig Count for
 
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
 
U.S. Land
    1,813       1,695       1,559       1,294       1,093  
U.S. Offshore
    65       73       90       89       97  
                                         
Total U.S.
    1,878       1,768       1,649       1,383       1,190  
Canada
    379       343       470       458       369  
                                         
Total North America
    2,257       2,111       2,119       1,841       1,559  
                                         
 
The average North American rig count for the year ended December 31, 2008 increased by 146 rigs, or 6.9%, compared to the year ended December 31, 2007. However, the rig count began to decline in the fourth quarter of 2008 and has fallen precipitously in early 2009 with a current rig count of approximately 1,760 rigs in North America, including 1,339 in the U.S.
 
Our well site services segment results for the year 2008 benefited from capital spending, which aggregated $227.0 million in the twelve months ended December 31, 2008 in that segment and included $43.0 million invested in our drilling services business, $75.0 million in our rental tools business and $109.0 million invested in our accommodations business, primarily in support of oil sands development in Canada. In addition, well site services benefited from the acquisitions discussed below of two rental tool companies for aggregate consideration of $113.0 million in the third quarter of 2007 and, to a lesser degree, the acquisition of an accommodations lodge in the oil sands region of Canada for aggregate consideration of $7.0 million in the first quarter of 2008.
 
For the year 2008, the Canadian dollar was valued at an average exchange rate of U.S. $0.94. In January 2009, the value of the Canadian dollar has weakened to an average exchange rate of $0.82 and hit a low in January of $0.79. Weakening of the Canadian dollar negatively impacts the translation of future earnings generated from our Canadian subsidiaries.
 
Some operators in the oil sands region of Canada have announced delays or cancellations of upgrades and new construction projects. For example, in November 2008, one of our customers announced the suspension of all activities associated with a development project in the Canadian oil sands during 2009 and amended its contract with us relating to the construction and rental of a 1,016 bed facility. The contract amendment will benefit our short term results of operations; however, the suspension will delay or eliminate revenues expected from the long term operation of this customer’s facility. See Note 17 to the Consolidated Financial Statements. We believe the longer term prospects for oil sands developments remain sound and we currently believe, based on our customer contracts and commitments, that our existing oil sands accommodations facilities will remain well utilized during 2009.


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In July and August 2007, we acquired two rental tool businesses for total consideration of approximately $113 million, which was funded primarily with borrowings under our bank credit facility. The acquired businesses provide well testing and flowback services and completion related rental tools in the U.S. market. The results of operations of the acquired businesses have been included in the rental tools business within the well site services segment since the date of acquisition. The rental tool business is expected to be negatively impacted in a material fashion by an industry wide reduction in drilling and completion activity. Since this equipment is highly mobile and, in many cases proprietary, we may be able to mitigate to some extent the effects of the downturn by moving equipment, as required, to one of our many rental tool locations in North America or, potentially, to foreign markets.
 
In 2008, we completed two acquisitions for total consideration of $29.9 million. In February 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., the owners of an accommodations lodge (Christina Lake Lodge) in the Conklin area of Alberta, Canada, for total consideration of $7.0 million. Christina Lake Lodge provides lodging and catering in the southern area of the oil sands region. The Christina Lake Lodge has been included in the accommodations business within the well site services segment since the date of acquisition. In February 2008, we also acquired a waterfront facility on the Houston ship channel for use in our offshore products segment for total consideration of $22.9 million. The new waterfront facility expanded our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities.
 
The major U.S. steel mills increased OCTG prices during 2008 because of high product demand, overall tight supplies and also in response to raw material and other cost increases. Given the tightness in OCTG supplies coupled with mill price increases and surcharges, our tubular services margins increased significantly in 2008. However, steel prices are declining on a global basis currently and industry inventories have increased significantly as the rig count has declined. We expect that these recent trends will have a material impact on OCTG pricing and, accordingly, on our revenues and margins realized during 2009 in the tubular services segment. These trends could also negatively impact the valuation of our OCTG inventory, potentially resulting in future lower of cost or market write-downs.
 
The current global financial crisis, which has contributed, among other things, to significant reductions in available capital and liquidity from banks and other providers of credit and has contributed to factors causing worldwide recessionary conditions. U.S. inventory levels for natural gas have risen higher than expected during the 2008 summer injection season and reached full theoretical capacity at the end of the season as was the case in 2007. The uncertainty surrounding future economic activity levels, the tightening of credit availability and the substantially reduced cash flow of our customers have already resulted in significantly decreased activity levels for some of our businesses. Spending cuts have been announced by our customers as a result of reduced oil and gas price expectations and the U.S. and North American active rig count and future rig count forecasts have been reduced significantly. In addition, exploration and production expenditures will be constrained to the extent exploration and production companies are limited in their access to the credit markets as a result of disruption in the lending markets. We have experienced a significant decline in utilization of our drilling rigs in late 2008 and thus far in 2009. Oil and gas prices have also declined precipitously from record highs reached in 2008. We currently expect that decreased energy prices and drilling will also negatively impact our other well site services businesses and tubular services business in 2009. We considered these factors, among others, in assessing goodwill for potential impairment. As a result of our assessment, we wrote off a total of $85.6 million, or $79.8 million after tax, of goodwill in our tubular services and drilling reporting units in the fourth quarter of 2008. There is significant uncertainty in the marketplace concerning the depth and duration of the current economic and energy business downturn. The recession is expected to negatively impact the oilfield services sectors in which we operate and, correspondingly, our results.
 
We continue to monitor the effect that the financial crisis has had on the global economy, the demand for crude oil and natural gas, and the resulting impact on the capital spending budgets of exploration and production companies in order to estimate the effect on our Company. We plan to reduce our capital spending significantly in 2009 compared to 2008. We currently expect that 2009 capital expenditures will total $147.0 million compared to 2008 capital expenditures of $247.4 million. In our well site services segment, we continue to monitor industry capacity additions and make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals. In our tubular services segment, we continue to focus on industry inventory levels, future drilling and completion activity and OCTG prices.


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Consolidated Results of Operations (in millions)
 
                                                         
    Year Ended
 
    December 31,  
                Variance
          Variance
 
                2008 vs. 2007           2007 vs. 2006  
    2008     2007     $     %     2006     $     %  
 
Revenues
                                                       
Well Site Services —
                                                       
Accommodations
  $ 427.1     $ 312.8     $ 114.3       37 %   $ 314.0     $ (1.2 )     0 %
Rental Tools
    355.8       260.4       95.4       37 %     200.6       59.8       30 %
Drilling and Other
    177.4       143.2       34.2       24 %     134.5       8.7       6 %
Workover Services
                      %     8.6       (8.6 )     (100 )%
                                                         
Total Well Site Services
    960.3       716.4       243.9       34 %     657.7       58.7       9 %
Offshore Products
    528.2       527.8       0.4       0 %     389.7       138.1       35 %
Tubular Services
    1,460.0       844.0       616.0       73 %     876.0       (32.0 )     (4 )%
                                                         
Total
  $ 2,948.5     $ 2,088.2     $ 860.3       41 %   $ 1,923.4     $ 164.8       9 %
                                                         
Product costs; Service and other costs (“Cost of sales and service”)
                                                       
Well Site Services —
                                                       
Accommodations
  $ 245.6     $ 182.1     $ 63.5       35 %   $ 208.6     $ (26.5 )     (13 )%
Rental Tools
    207.3       135.5       71.8       53 %     94.4       41.1       44 %
Drilling and Other
    114.2       88.3       25.9       29 %     69.1       19.2       28 %
Workover Services
                      %     5.3       (5.3 )     (100 )%
                                                         
Total Well Site Services
    567.1       405.9       161.2       40 %     377.4       28.5       8 %
Offshore Products
    394.2       403.1       (8.9 )     (2 )%     293.9       109.2       37 %
Tubular Services
    1,273.7       793.2       480.5       61 %     796.7       (3.5 )     0 %
                                                         
Total
  $ 2,235.0     $ 1,602.2     $ 632.8       39 %   $ 1,468.0     $ 134.2       9 %
                                                         
Gross margin
                                                       
Well Site Services —
                                                       
Accommodations
  $ 181.5     $ 130.7     $ 50.8       39 %   $ 105.4     $ 25.3       24 %
Rental Tools
    148.5       124.9       23.6       19 %     106.2       18.7       18 %
Drilling and Other
    63.2       54.9       8.3       15 %     65.4       (10.5 )     (16 )%
Workover Services
                      %     3.3       (3.3 )     (100 )%
                                                         
Total Well Site Services
    393.2       310.5       82.7       27 %     280.3       30.2       11 %
Offshore Products
    134.0       124.7       9.3       7 %     95.8       28.9       30 %
Tubular Services
    186.3       50.8       135.5       267 %     79.3       (28.5 )     (36 )%
                                                         
Total
  $ 713.5     $ 486.0     $ 227.5       47 %   $ 455.4     $ 30.6       7 %
                                                         
Gross margin as a percent of revenues
                                                       
Well Site Services —
                                                       
Accommodations
    42 %     42 %                     34 %                
Rental Tools
    42 %     48 %                     53 %                
Drilling and Other
    36 %     38 %                     49 %                
Workover Services
    %     %                     38 %                
Total Well Site Services
    41 %     43 %                     43 %                
Offshore Products
    25 %     24 %                     25 %                
Tubular Services
    13 %     6 %                     9 %                
Total
    24 %     23 %                     24 %                


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YEAR ENDED DECEMBER 31, 2008 COMPARED TO YEAR ENDED DECEMBER 31, 2007
 
We reported net income for the year ended December 31, 2008 of $222.7 million, or $4.33 per diluted share, as compared to $203.4 million, or $3.99 per diluted share, reported for the year ended December 31, 2007. Net income in 2008 included an after tax loss of $79.8 million, or approximately $1.55 per diluted share, on the impairment of goodwill in our tubular services and drilling reporting units. See Note 6 to the Consolidated Financial Statements included in this Annual Report on Form 10-K. Net income in 2008 also included an after tax gain of $3.6 million, or approximately $0.07 per diluted share, on the sale of 11.51 million shares of Boots & Coots common stock. Net income in 2007 included an after tax gain of $8.4 million, or $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots common stock. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Revenues.  Consolidated revenues increased $860.3 million, or 41%, in 2008 compared to 2007.
 
Our well site services segment revenues increased $243.9 million, or 34%, in 2008 compared to 2007.
 
Our accommodations business reported revenues in 2008 that were $114.3 million, or 37%, above 2007 primarily because of the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada.
 
Our rental tools revenues increased $95.4 million, or 37%, in 2008 compared to 2007 primarily as a result of two acquisitions completed in the third quarter of 2007, capital additions made in both years, geographic expansion of our rental tool operations and increased rental tool utilization.
 
Our drilling and other revenues increased $34.2 million, or 24%, in 2008 compared to 2007 primarily as a result of an increased rig fleet size (three additional rigs) and higher dayrates. Our utilization averaged 82.4% during 2008 compared to 79.3% in 2007.
 
Our offshore products segment revenues were essentially flat at $528.2 million in 2008 compared to $527.8 million in 2007.
 
Tubular services segment revenues increased $616.0 million, or 73%, in 2008 compared to 2007 as a result of a 38.5% increase in average selling prices per ton due to a tight OCTG supply demand balance caused by higher drilling activity and lower overall industry inventory levels and a 24.9% increase in tons shipped.
 
Cost of Sales and Service.  Our consolidated cost of sales increased $632.8 million, or 39%, in 2008 compared to 2007 primarily as a result of increased cost of sales at tubular services of $480.5 million, or 61%, and at well site services of $161.2 million, or 40%. Our overall gross margin as a percent of revenues was relatively constant at 24% in 2008 compared to 23% in 2007.
 
Our well site services segment gross margin as a percent of revenues declined from 43% in 2007 to 41% in 2008. Our accommodations gross margin as a percent of revenues was 42% in both 2007 and 2008. Our rental tools cost of sales increased $71.8 million, or 53%, in 2008 compared to 2007 substantially due to the two acquisitions completed in the third quarter of 2007, increased revenues, higher rebillable third-party expenses, increased wages and cost increases for fuel, parts and supplies. The rental tool gross margin as a percent of revenues was 42% in 2008 compared to 48% in 2007 and declined due to a higher proportion of lower margin rebill revenue and the impact of the above mentioned cost increases.
 
Our drilling services cost of sales increased $25.9 million, or 29%, in 2008 compared to 2007 as a result of an increase in the number of rigs that we operate; however, our gross margin as a percent of revenue decreased from 38% in 2007 to 36% in 2008 as a result of increased wages and cost increases for repairs, supplies and other rig operating expenses.
 
Our offshore products segment cost of sales were relatively flat in 2008 compared to 2007, and coupled with relatively flat revenues year over year, resulting in gross margins as a percent of revenues of 25% in 2008 and 24% in 2007.


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Tubular services segment cost of sales increased by $480.5 million, or 60.6%, as a result of higher tonnage shipped and higher pricing charged by the OCTG suppliers. Our tubular services gross margin as a percentage of revenues increased from 6% in 2007 to 13% in 2008.
 
Selling, General and Administrative Expenses.  SG&A increased $24.7 million, or 21%, in 2008 compared to 2007 due primarily to SG&A expense associated with acquisitions made in July and August of 2007, increased bonuses and equity compensation expense and an increase in headcount. SG&A was 4.9% of revenues in 2008 compared to 5.7% of revenues in 2007 as we successfully spread our S,G&A costs over our larger revenue base.
 
Depreciation and Amortization.  Depreciation and amortization expense increased $31.9 million, or 45%, in 2008 compared to 2007 due primarily to capital expenditures made during the previous twelve months and to the two rental tool acquisitions closed in the third quarter of 2007.
 
Impairment of Goodwill.  We recorded a goodwill impairment of $85.6 million, before tax, in 2008. The impairment was the result of our assessment of several factors affecting our tubular services and drilling reporting units. See Note 6 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Operating Income.  Consolidated operating income increased $86.0 million, or 29%, in 2008 compared to 2007 primarily as a result of increases at tubular services of $130.9 million, or 340%, and at well site services of $39.1 million, or 20%, which were partially offset by an $85.6 million pre-tax goodwill impairment charge recorded in the fourth quarter of 2008.
 
Gain on Sale of Investment.  We reported gains on the sales of investment of $6.2 million and $12.8 million in 2008 and 2007, respectively. In both periods, the sales related to our investment in Boots & Coots common stock and the larger gain in 2007 was primarily attributable to the larger number of shares sold in 2007. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Interest Expense and Interest Income.  Net interest expense decreased by $0.5 million, or 3% in 2008 compared to 2007 due to lower interest rates partially offset by higher average debt levels. The weighted average interest rate on the Company’s revolving credit facility was 3.9% in 2008 compared to 6.0% in 2007. Interest income in 2006 through 2008 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Equity in Earnings of Unconsolidated Affiliates.  Our equity in earnings of unconsolidated affiliates is $0.7 million higher in 2008 than in 2007 primarily because of increased earnings from our investment in Boots & Coots, prior to the discontinuance of the equity method of accounting on June 30, 2008.
 
Income Tax Expense.  Our income tax provision for the year ended December 31, 2008 totaled $156.3 million, or 41.2% of pretax income, compared to $97.0 million, or 32.3% of pretax income, for the year ended December 31, 2007. The higher effective tax rate was primarily due to the impairment of goodwill, the majority of which was not deductible for tax purposes.
 
YEAR ENDED DECEMBER 31, 2007 COMPARED TO YEAR ENDED DECEMBER 31, 2006
 
We reported increased net income for the year ended December 31, 2007 of $203.4 million, or $3.99 per diluted share, as compared to $197.6 million, or $3.89 per diluted share, reported for the year ended December 31, 2006. Net income in 2007 included a pre-tax gain of $12.8 million, or an after tax gain of $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots common stock. Net income in 2006 included the recognition of a non-cash, pre-tax gain of $11.3 million, or an after-tax gain of $0.12 per diluted share, on the sale of the Company’s workover services business to Boots & Coots. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Revenues.  Consolidated revenues increased $164.8 million, or 9%, in 2007 compared to 2006.
 
Our well site services segment revenues increased $58.7 million, or 9%, in 2007 compared to 2006.
 
Our accommodations business revenues decreased $1.2 million, or 0.4%, as a result of decreased oil and gas drilling activity levels in Canada and lower third party accommodations manufacturing revenues in the U.S. and


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Canada, which were only partially offset by higher revenues driven by increased activity in support of the oil sands developments in Canada.
 
Rental tools revenues increased $59.8 million, or 30%, in 2007 compared to 2006 as a result of two rental tool acquisitions completed during the third quarter, increased prices realized and capital additions made in both years, which were partially offset by decreased Canadian rental tool revenues in 2007 caused by reduced Canadian drilling and completion activity when compared to 2006.
 
Our drilling and other revenues increased $8.7 million, or 6%, in 2007 compared to 2006 as a result of an increased rig fleet size (three additional rigs) and higher dayrates, partially offset by lower utilization in 2007. Our utilization declined from 90.0% in 2006 to 79.3% in 2007 due primarily to softness in demand in West Texas, the impact of industry capacity additions and extended holiday downtime in the fourth quarter. The sale of our workover services business in March 2006 caused an $8.6 million decrease in revenues in 2007 compared to 2006.
 
Our offshore products segment revenues increased $138.1 million, or 35%, due to increased deepwater development spending and capital equipment upgrades by our customers which increased demand for our products and services.
 
Tubular services segment revenues decreased $32.0 million, or 4%, in 2007 compared to 2006 as a result of a 4.6% decrease in average selling prices per ton of OCTG partially offset by a 1% increase in tons shipped.
 
Cost of Sales and Service.  Our consolidated cost of sales increased $134.2 million, or 9%, in 2007 compared to 2006 primarily as a result of an increase at offshore products of $109.2 million, or 37%. Our overall gross margin as a percent of revenues decreased to 23% in 2007 from 24% in 2006.
 
Our well site services segment gross margin as a percent of revenues was 43% in both 2007 and 2006. Our accommodations cost of sales decreased due to lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and reduced activity in support of conventional Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from 34% in 2006 to 42% in 2007 primarily because of capacity additions and economies of scale in our major oil sands lodges and lower manufacturing revenues, which generally earn lower margins than accommodations rentals or catering work.
 
Our rental tool cost of sales increased $41.1 million, or 44%, in 2007 compared to 2006 primarily as a result of operating costs associated with two acquisitions made in the third quarter of 2007 and higher costs associated with increased revenue at our existing rental tool businesses. Our rental tool gross margin decreased from 53% in 2006 to 48% in 2007 primarily as a result of margins attributable to one of the acquired business lines which are typically lower than our existing rental tool businesses and due to the mix of rental equipment and service personnel used in the business. In addition, cost of sales and gross margins decreased in Canada due to reduced rental activity.
 
Our drilling services cost of sales increased $19.2 million, or 28%, in 2007 compared to 2006 as a result of an increase in the number of rigs that we operate, increased wages paid to our employees and increased costs associated with footage-based drilling contracts in 2007. Increased costs coupled with lower utilization reduced our drilling services gross margin from 49% in 2006 to 38% in 2007.
 
Our offshore products segment cost of sales, on a percentage basis, increased approximately in line with the increase in offshore products revenues resulting in no change in the gross margin percentage for that segment.
 
Our tubular services segment gross margin as a percentage of revenues decreased from 9% to 6% in 2007 compared to 2006 primarily as a result of lower OCTG mill pricing and a more competitive tubular marketplace.
 
Selling, General and Administrative Expenses.  SG&A increased $11.2 million, or 10%, in 2007 compared to 2006 due primarily to SG&A expense associated with two acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in headcount. SG&A was 5.7% of revenues in the 2007 compared to 5.6% of revenues in 2006.
 
Depreciation and Amortization.  Depreciation and amortization expense increased $16.4 million, or 30%, in 2007 compared to 2006 due primarily to capital expenditures made in 2006 and 2007.


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Operating Income.  Consolidated operating income decreased $0.2 million, or 0.1%, in 2007 compared to 2006 primarily as a result of decreased tubular services operating income of $28.0 million, or 42%, which was partially offset by increases at offshore products of $26.5 million, or 47%, and at well site services of $2.5 million, or 1%.
 
Interest Expense and Interest Income.  Net interest expense decreased by $1.4 million, or 7% in 2007 compared to 2006 due to lower average debt levels. The weighted average interest rate on the Company’s revolving credit facility was 6.0% in 2007 compared to 6.2% in 2006. Interest income in 2007 and 2006 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Equity in Earnings of Unconsolidated Affiliates.  Our equity in earnings of unconsolidated affiliates is lower in 2007 than in 2006 due to lower earnings of Boots & Coots and the sale of 14.95 million shares of our investment in Boots & Coots in April 2007. Following this sale, our ownership interest decreased from 45.6% to approximately 15%.
 
Income Tax Expense.  Our income tax provision for the year ended December 31, 2007 totaled $97.0 million, or 32.3% of pretax income, compared to $104.0 million, or 34.5% of pretax income, for the year ended December 31, 2006. Lower Canadian and other foreign taxes on income and dividends, a higher allowable manufacturing credit and the completion of the IRS audit of the Company’s 2004 federal income tax return, which resulted in a favorable adjustment in the Company’s allowance for uncertain tax positions, lowered the effective tax rate in the year ended December 31, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.
 
Liquidity and Capital Resources
 
The recent and unprecedented disruption in the credit markets has had a significant adverse impact on a number of financial institutions. To date, the Company’s liquidity has not been materially impacted by the current credit environment. The Company is not currently a party to any interest rate swaps, currency hedges or derivative contracts of any type and has no exposure to commercial paper or auction rate securities markets. Management will continue to closely monitor the Company’s liquidity and the overall health of the credit markets. However, management cannot predict with any certainty the direct impact on the Company of any further disruption in the credit environment, although the Company is seeing the negative impact that such disruptions are currently having on the energy market generally.
 
Our primary liquidity needs are to fund capital expenditures, which typically have included expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, adding drilling rigs and increasing and replacing rental tool assets, funding new product development and general working capital needs. In addition, capital has been used to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and proceeds from our $175 million convertible note offering in 2005. See Note 8 to Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
Cash totaling $257.5 million was provided by operations during the year ended December 31, 2008 compared to cash totaling $247.9 million provided by operations during the year ended December 31, 2007. During 2008, $171.5 million was used to fund working capital, primarily for OCTG inventories in our tubular services segment due to increased volumes and prices paid. We have significantly reduced our forward OCTG purchase commitments beginning in the fourth quarter of 2008 and expect our OCTG inventory levels to decrease in 2009. During 2007, $15.9 million was used to fund working capital due primarily to growth in activity in our offshore products and Canadian accommodations segments. These increases in working capital were partially offset by a $70.0 million reduction in working capital for inventories in our tubular services segment in 2007.
 
Cash was used in investing activities during the years ended December 31, 2008 and 2007 in the amount of $246.1 million and $310.8 million, respectively. Capital expenditures, including capitalized interest, totaled $247.4 million and $239.6 million during the years ended December 31, 2008 and 2007, respectively. Capital


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expenditures in both years consisted principally of purchases of assets for our well site services segment, particularly for accommodations investments made in support of Canadian oil sands development. Net proceeds from the sale of Boots & Coots common stock totaled $27.4 million and $29.4 million during the years ended December 31, 2008 and 2007, respectively. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
 
During the year ended December 31, 2008, we spent cash of $29.8 million to acquire Christina Lake Lodge in Northern Alberta, Canada to expand our oil sands capacity in our well site services segment and to acquire a waterfront facility on the Houston ship channel for use in the offshore products segment. This compares to $103.1 million spent, net of cash acquired, during the year ended December 31, 2007 to acquire two rental tool businesses.
 
The cash consideration paid for all of our acquisitions in the period was funded utilizing our existing bank credit facility.
 
We plan to significantly reduce our capital spending in 2009 compared to 2008. We currently expect to spend a total of approximately $147 million for capital expenditures during 2009 to expand our Canadian oil sands related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. We expect to fund these capital expenditures with internally generated funds. The foregoing capital expenditure budget does not include any funds for opportunistic acquisitions or expansion projects, which the Company expects to pursue depending on the economic environment in our industry and the availability of transactions at prices deemed attractive to the Company. If there is a significant decrease in demand for our products and services as a result of further declines in the actual and longer term expected price of oil and gas, we may further reduce our capital expenditures and have reduced requirements for working capital, both of which would increase operating cash flow and liquidity. However, such an environment might also increase the availability of attractive acquisitions which would draw on such liquidity.
 
We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in 2009. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and in the financial markets and other financial, business factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.
 
Net cash of $1.7 million was used in financing activities during the year ended December 31, 2008, primarily as a result of treasury stock purchases partially offset by other financing activities. A total of $60.6 million was provided by financing activities during the year ended December 31, 2007, primarily as a result of revolving credit borrowings to fund acquisitions and capital expenditures partially offset by treasury stock purchases.
 
Stock Repurchase Program.  During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50.0 million was approved and the duration of the program was extended to August 31, 2008. On January 11, 2008, an additional $50.0 million was approved for the repurchase program and the duration of the program was again extended to December 31, 2009. Through February 12, 2009, a total of $90.1 million of our stock (3,162,344 shares), has been repurchased under this program, leaving a total of up to approximately $59.9 million remaining available under the program to make share repurchases. We will continue to evaluate future share repurchases in the context of allocating capital among other corporate opportunities including capital expenditures and acquisitions and in the context of current conditions in the credit and capital markets.


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Credit Facility.  On December 13, 2007, we entered into an Incremental Assumption Agreement (Agreement) with the lenders and other parties to our existing credit agreement dated as of October 30, 2003 (Credit Agreement) in order to exercise the accordion feature (Accordion) available under the Credit Agreement and extend maturity to December 5, 2011. The Accordion increased the total commitments under the Credit Agreement from $400 million to $500 million. In connection with the execution of the Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $300 million to U.S. $325 million, and the Total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $100 million to U.S. $175 million. We currently have 11 lenders in our Credit Agreement with commitments ranging from $15 million to $102.5 million. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, the lack of or delay in funding by a significant member of our banking group could negatively affect our liquidity position.
 
The Credit Agreement, which governs our credit facility, contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt, to consolidated EBITDA of no greater than 3.25 to 1.0 in 2009 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2008, we were in compliance with our debt covenants and expect to continue to be in compliance during 2009. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During the year 2008, our applicable margin over LIBOR ranged from 0.5% to 0.75% and it was 0.5% as of December 31, 2008. Our weighted average interest rate paid under the Credit Agreement was 3.9% during the year ended December 31, 2008 and 6.0% for the year ended December 31, 2007.
 
As of December 31, 2008, we had $287.2 million outstanding under the Credit Agreement and an additional $16.8 million of outstanding letters of credit, leaving $196.0 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $7.9 million. As of December 31, 2008, we had $4.2 million outstanding under these other facilities and an additional $1.1 million of outstanding letters of credit leaving $2.6 million available to be drawn under these facilities. Our total debt represented 28.2% of our total debt and shareholder’s equity at December 31, 2008 compared to 31.2% at December 31, 2007.
 
Contingent Convertible Notes.  In June 2005, we sold $175 million aggregate principal amount of 23/8% contingent convertible notes due 2025. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were included in the calculation of diluted earnings per share during the year because our stock price exceeded the initial conversion price of $31.75 during the period. The terms of the notes require that our stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price (or $38.10 per share) for at least 20 trading days in a defined period before the notes are convertible. If a note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 23/8% note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 23/8% notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 23/8% Notes for conversion. For a more detailed description of our 23/8% contingent convertible notes, please see Note 8 to the Consolidated Financial Statements included in this annual report on Form 10-K.
 
As of December 31, 2008, we have classified the $175.0 million principal amount of our 23/8% Contingent Convertible Senior Notes (23/8% Notes) as a noncurrent liability because certain contingent conversion thresholds based on the Company’s stock price were not met at that date and, as a result, note holders could not present their


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notes for conversion during the quarter following the December 31, 2008 measurement date. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company common stock during the prescribed measurement periods. As of December 31, 2008, the recent trading prices of the 23/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. The trading price for the 23/8% Notes is dependent on current market conditions, the length of time until the first put / call date in July 2012 of the 23/8% Notes and general market liquidity, among other factors. In May 2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which will change the accounting for our 23/8% Notes. Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity will be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the new rules on our 23/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense will result by recognizing the accretion of the discounted carrying value of the debt component of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. In addition to a reduction of debt balances and an increase to stockholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively. As of January 1, 2009, the amortized balance of the 23/8% Notes will be $149.1 million.
 
Contractual Cash Obligations.  The following summarizes our contractual obligations at December 31, 2008 (in thousands):
 
                                         
          Due in Less
    Due in
    Due in
    Due After
 
December 31, 2008
  Total     than 1 year     1-3 years     3 - 5 years     5 years  
 
Contractual obligations:
                                       
Total debt, including capital leases(1)
  $ 479,891     $ 4,943     $ 292,289     $ 175,703     $ 6,956  
Non-cancelable operating leases
    25,604       6,499       8,420       5,315       5,370  
Purchase obligations
    441,308       441,308                    
                                         
Total contractual cash obligations
  $ 946,803     $ 452,750     $ 300,709     $ 181,018     $ 12,326  
                                         
 
 
(1) Excludes interest on debt.
 
Our debt obligations at December 31, 2008 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 assumed the redemption of our 23/8% Contingent Convertible Notes due in 2025 at the note holders’ first optional redemption date in 2012. We have not entered into any material leases subsequent to December 31, 2008.
 
Off-Balance Sheet Arrangements
 
As of December 31, 2008, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.
 
Tax Matters
 
Our primary deferred tax assets at December 31, 2008, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill and $15 million in available federal net operating loss carryforwards, or regular tax NOLs, as of that date. The regular tax NOLs will expire in varying amounts during the years 2010


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through 2011 if they are not first used to offset taxable income that we generate. Our ability to utilize a significant portion of the available regular tax NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. We currently believe that substantially all of our regular tax NOLs will be utilized. The Company has utilized all federal alternative minimum tax net operating loss carryforwards.
 
Our income tax provision for the year ended December 31, 2008 totaled $156.3 million, or 41.2% of pretax income. The higher effective tax rate was primarily due to the impairment of goodwill, the majority of which was not deductible for tax purposes. During the year ended December 31, 2008, the Company recognized a tax benefit triggered by employee exercises of stock options totaling $3.4 million. Such benefit, which lowered cash paid for taxes, was credited to additional paid-in capital. Our income tax provision for the year ended December 31, 2007 totaled $97.0 million, or 32.3% of pretax income.
 
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.
 
Accounting for Contingencies
 
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, interest, insurance claims, warranty claims, contract claims and discontinued operations.
 
Tangible and Intangible Assets, including Goodwill
 
Our goodwill totals $305.4 million, or 13.3%, of our total assets, as of December 31, 2008. The assessment of impairment on long-lived assets, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. The determination of the amount of impairment, would be based on quoted market prices, if available, or upon 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 will be generated, as well as the predictability of these cash flows and our determination of whether an other than temporary decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
 
On an annual basis in December, we review each reporting unit, as defined in FASB Statement No. 142 — Goodwill and Other Intangible Assets (FAS #142), to assess goodwill for potential impairment. Our reporting units include accommodations, rental tools, drilling, offshore products and tubular services. As part of the goodwill impairment analysis, we estimate the implied fair value of each reporting unit (IFV) and compare the IFV to the carrying value of such unit (the Carrying Value). Because none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process. In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilized, depending on circumstances, trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is affected by future oil and gas


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prices, anticipated spending by our customers, and the cost of capital. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered impaired, and additional analysis in accordance with FAS #142 is conducted to determine the amount of impairment, if any.
 
As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV’s of all of our reporting units to assess the reasonableness of the IFV’s in the aggregate.
 
Revenue and Cost Recognition
 
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.
 
Valuation Allowances
 
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 have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized (see Note 10 — Income Taxes in the Consolidated Financial Statements included in this Annual Report on Form 10-K and Tax Matters herein).
 
Estimation of Useful Lives
 
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.
 
Stock Based Compensation
 
Since the adoption of SFAS No. 123R, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms, option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.
 
Income Taxes
 
In accounting for income taxes, we are required by the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to


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which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
 
Recent Accounting Pronouncements
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. We adopted those provisions of SFAS 157 that were unaffected by the delay in the first quarter of 2008. Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows.
 
In February 2007, the FASB issued SFAS No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has chosen not to adopt the elective provisions of SFAS 159 for its existing financial instruments.
 
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for fiscal years beginning after December 15, 2008. Since SFAS 141R will be adopted prospectively, it is not possible to determine the effect, if any, on the Company’s results from operations or financial position.
 
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material impact on our results from operations or financial position.
 
In May 2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which will change the accounting for our 23/8% Notes. Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity will be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the new rules on our 23/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense will result by recognizing


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the accretion of the discounted carrying value of the debt component of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. In addition to a reduction of debt balances and an increase to stockholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively. As of January 1, 2009, the amortized balance of the 23/8% Notes will be $149.1 million.
 
See also Note 10 — Income Taxes for a discussion of the FASB’s Interpretation No. 48 — Accounting for Uncertainty in Income Taxes.
 
ITEM 7A.   Quantitative And Qualitative Disclosures About Market Risk
 
Interest Rate Risk.  We have long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of December 31, 2008, we had floating rate obligations totaling approximately $291.4 million for amounts borrowed under our revolving credit facilities. 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, 2008 levels, our consolidated interest expense would increase by a total of approximately $2.9 million annually.
 
Foreign Currency Exchange Rate Risk.  Our operations are conducted in various countries around the world and we receive revenue from these operations 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, or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. 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. During 2008, our realized foreign exchange gains were $1.6 million and are included in other operating expense (income) in the consolidated statements of income.
 
Item 8.   Financial Statements and Supplementary Data
 
Our consolidated financial statements and supplementary data of the Company appear on pages 52 through 84 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 15 to our Consolidated 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.
 
Item 9A.   Controls and Procedures
 
(i)   Evaluation of Disclosure Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures.  As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive


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Officer and Chief Financial Officer, on a timely basis to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act, including this Annual Report on Form 10-K, is recorded, processed, summarized and reported within the time periods specified in the Commission rules and forms.
 
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.
 
(ii)   Internal Control Over Financial Reporting
 
(a)   Management’s annual report on internal control over financial reporting.
 
The Company’s management report on internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 53 and is incorporated herein by reference.
 
(b)   Attestation report of the registered public accounting firm.
 
The attestation report of Ernst & Young LLP, the Company’s independent registered public accounting firm, on the Company’s internal control over financial reporting is set forth in this Annual Report on Form 10-K on Pages 54 and 55 and is incorporated herein by reference.
 
(c)   Changes in internal control over financial reporting.
 
During the Company’s fourth fiscal quarter ended December 31, 2008, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.
 
Item 9B.   Other Information
 
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2008 that was not reported on a Form 8-K during such time.
 
PART III
 
Item 10.   Director, Executive Officers and Corporate Governance
 
(1) Information concerning directors, including the Company’s audit committee financial expert, appears in the Company’s Definitive Proxy Statement for the 2009 Annual Meeting of Stockholders, 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 for the 2009 Annual Meeting of Stockholders, 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 for the 2009 Annual Meeting of Stockholders, under “Section 16(a) Beneficial Ownership Reporting Compliance.” This portion of the Definitive Proxy Statement is incorporated herein by reference.
 
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 2009 Annual Meeting of Stockholders.


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Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2009 Annual Meeting of Stockholders.
 
Item 13.   Certain Relationships and Related Transactions, and Director Independence
 
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 2009 Annual Meeting of Stockholders.
 
Item 14.   Principal Accountant 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 for the 2009 Annual Meeting of Stockholders under the heading “Fees Paid to Ernst & Young LLP” and is incorporated herein by reference.
 
PART IV
 
Item 15.   Exhibits and Financial Statement Schedules
 
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
 
(1) Financial Statements: Reference is made to the index set forth on page 52 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 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) 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).
  3 .2     Second Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 21, 2008).
  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).
  4 .4     Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005).


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Exhibit No.
     
Description
 
  4 .5     Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Oil States’ Current Report on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005).
  4 .6     Global Notes representing $175,000,000 aggregate principal amount of 23/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 hereof) (incorporated by reference to Oil States’ Current Reports on Form 8-K filed with the Securities and Exchange Commission on June 23, 2005 and July 13, 2005).
  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 as amended and restated effective February 16, 2005 (incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, as filed with the Commission on March 2, 2006).
  10 .6**     Deferred Compensation Plan effective November 1, 2003 (incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, as filed with the Commission on March 5, 2004).
  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 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 .9**     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 .10**     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 .11     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 10-Q for the three months ended September 30, 2003, as filed with the Commission on November 11, 2003.)
  10 .11A     Incremental Assumption Agreement, dated as of May 10, 2004, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12A to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2004, as filed with the Commission on August 4, 2004).

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Exhibit No.
     
Description
 
  10 .11B     Amendment No. 1, dated as of January 31, 2005, to the Credit Agreement 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 10.12b to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005).
  10 .11C     Amendment No. 2, dated as of December 5, 2006, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12C to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 7, 2006).
  10 .11D     Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on December 18, 2007).
  10 .12**     Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004).
  10 .13**     Form of Director Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005).
  10 .14**     Form of Employee Non Qualified Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005).
  10 .15**     Form of Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on November 15, 2006).
  10 .16**     Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company’s Report on Form 8-K as filed with the Commission on May 24, 2005).
  10 .17**     Form of Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005).
  10 .18**     Form of Non-Employee Director Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 22.2 to the Company’s Report of Form 8-K, as filed with the Commission on May 24, 2005).
  10 .19**     Form of Executive Agreement between Oil States International, Inc. and named executive officer (Bradley Dodson) effective October 10, 2006 (incorporated by reference to Exhibit 10.24 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, as filed with the Commission on November 3, 2006).
  10 .20**     Form of Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007.
  10 .21**,*     Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009.
  10 .22**,*     Amendment to the Executive Agreement of Bradley Dodson, effective January 1, 2009.
  10 .23**,*     Amendment to the Executive Agreement of Howard Hughes, effective January 1, 2009.
  10 .24**,*     Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009.
  10 .25**,*     Amendment to the Executive Agreement of Ron Green, effective January 1, 2009.

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Exhibit No.
     
Description
 
  10 .26**,*     Amendment to the Executive Agreement of Robert Hampton, effective January 1, 2009.
  21 .1*     List of subsidiaries of the Company.
  23 .1*     Consent of Independent Registered Public Accounting Firm.
  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.
 
 
* Filed herewith
 
** Management contracts or compensatory plans or arrangements
 
*** Furnished herewith.

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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/  CINDY B. TAYLOR
Cindy B. Taylor
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 February 20, 2009.
 
         
Signature
 
Title
 
     
STEPHEN A. WELLS*

Stephen A. Wells*
  Chairman of the Board
     
/s/  CINDY B. TAYLOR

Cindy B. Taylor
  Director, President & Chief Executive Officer (Principal Executive Officer)
     
/s/  BRADLEY J. DODSON

Bradley J. Dodson
  Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
     
/s/  ROBERT W. HAMPTON

Robert W. Hampton
  Senior Vice President — Accounting and Corporate Secretary (Principal Accounting Officer)
     
/s/  MARTIN LAMBERT*

Martin Lambert*
  Director
     
/s/  S. JAMES NELSON, JR.*

S. James Nelson, Jr.*
  Director
     
/s/  MARK G. PAPA*

Mark G. Papa*
  Director
     
/s/  GARY L. ROSENTHAL*

Gary L. Rosenthal*
  Director
     
/s/  CHRISTOPHER T. SEAVER*

Christopher T. Seaver*
  Director
     
/s/  DOUGLAS E. SWANSON*

Douglas E. Swanson*
  Director
     
/s/  WILLIAM T. VAN KLEEF*

William T. Van Kleef*
  Director
         
*By:  
/s/  BRADLEY J. DODSON

Bradley J. Dodson, pursuant to a power of attorney filed as Exhibit 24.1 to this Annual Report on Form 10-K
   


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
INDEX TO
 
CONSOLIDATED FINANCIAL STATEMENTS
 
         
    53  
    54  
    55  
    56  
    57  
    58  
    59  
    60–84  


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
 
To the Stockholders and Board of Directors of Oil States International, Inc.:
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.
 
Oil States International, Inc.’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.
 
Oil States International, Inc.’s independent registered public accounting firm has audited the Company’s internal control over financial reporting. This report appears on Page 55.
 
OIL STATES INTERNATIONAL, INC.
 
Houston, Texas


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To 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 (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 10 to the consolidated financial statements, effective January 1, 2007 the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2009 expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 18, 2009


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholders of Oil States International, Inc.:
 
We have audited Oil States International, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2008 and 2007, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 18, 2009 expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 18, 2009


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands, except per share amounts)  
 
Revenues:
                       
Product
  $ 1,874,262     $ 1,280,235     $ 1,232,149  
Service and other
    1,074,195       808,000       691,208  
                         
      2,948,457       2,088,235       1,923,357  
                         
Costs and expenses:
                       
Product costs
    1,594,139       1,135,354       1,082,379  
Service and other costs
    640,835       466,859       385,609  
Selling, general and administrative expenses
    143,080       118,421       107,216  
Depreciation and amortization expense
    102,604       70,703       54,340  
Impairment of goodwill
    85,630              
Other operating income
    (1,586 )     (888 )     (4,124 )
                         
      2,564,702       1,790,449       1,625,420  
                         
Operating income
    383,755       297,786       297,937  
Interest expense
    (17,530 )     (17,988 )     (19,389 )
Interest income
    3,561       3,508       2,506  
Equity in earnings of unconsolidated affiliates
    4,035       3,350       7,148  
Gains on sale of workover services business and resulting equity investment
    6,160       12,774       11,250  
Other income / (expense)
    (922 )     928       2,195  
                         
Income before income taxes
    379,059       300,358       301,647  
Income tax provision
    (156,349 )     (96,986 )     (104,013 )
                         
Net income attributable to common shares
  $ 222,710     $ 203,372     $ 197,634  
                         
Basic net income per share
  $ 4.49     $ 4.11     $ 3.99  
Diluted net income per share
  $ 4.33     $ 3.99     $ 3.89  
Weighted average number of common shares outstanding (in thousands):
                       
Basic
    49,622       49,500       49,519  
Diluted
    51,414       50,911       50,773  
 
The accompanying notes are an integral part of these financial statements.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2008     2007  
    (In thousands, except share amounts)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 30,199     $ 30,592  
Accounts receivable, net
    575,982       450,153  
Inventories, net
    612,488       349,347  
Prepaid expenses and other current assets
    18,815       35,575  
                 
Total current assets
    1,237,484       865,667  
Property, plant and equipment, net
    695,338       586,910  
Goodwill, net
    305,441       391,644  
Investments in unconsolidated affiliates
    5,899       24,778  
Other noncurrent assets
    55,085       60,627  
                 
Total assets
  $ 2,299,247     $ 1,929,626  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable and accrued liabilities
  $ 371,789     $ 239,119  
Income taxes
    52,546       43  
Current portion of long-term debt
    4,943       4,718  
Deferred revenue
    105,640       60,910  
Other current liabilities
    1,587       121  
                 
Total current liabilities
    536,505       304,911  
Long-term debt
    474,948       487,102  
Deferred income taxes
    55,646       40,550  
Other noncurrent liabilities
    13,155       12,236  
                 
Total liabilities
    1,080,254       844,799  
Stockholders’ equity:
               
Common stock, $.01 par value, 200,000,000 shares authorized, 49,500,708 shares and 49,392,106 shares issued and outstanding, respectively
    526       522  
Additional paid-in capital
    425,284       402,091  
Retained earnings
    913,423       690,713  
Accumulated other comprehensive income (loss)
    (28,409 )     73,036  
Common stock held in treasury at cost, 3,206,645 and 2,814,302 shares, respectively
    (91,831 )     (81,535 )
                 
Total stockholders’ equity
    1,218,993       1,084,827  
                 
Total liabilities and stockholders’ equity
  $ 2,299,247     $ 1,929,626  
                 
 
The accompanying notes are an integral part of these financial statements.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
(In thousands)
 
                                                 
                            Accumulated
       
                            Other
       
          Additional
                Comprehensive
       
    Common
    Paid-In
    Retained
    Comprehensive
    Income
    Treasury
 
    Stock     Capital     Earnings     Income     (Loss)     Stock  
 
Balance, December 31, 2005
  $ 504     $ 350,667     $ 289,993             $ 23,137     $ (30,317 )
Net income
                    197,634     $ 197,634                  
Currency translation adjustment
                            7,016       7,016          
Other comprehensive income
                            30       30          
                                                 
Comprehensive income
                          $ 204,680                  
                                                 
Exercise of stock options, including tax benefit
    7       13,494                                  
Amortization of restricted stock compensation
            1,949                                  
Restricted stock award
            140                               (303 )
                                                 
Stock option expense
            5,647                                  
Stock acquired for cash
                                            (19,970 )
Stock sold in deferred compensation plan
            146                               62  
                                                 
Balance, December 31, 2006
  $ 511     $ 372,043     $ 487,627             $ 30,183     $ (50,528 )
Net income
                    203,372     $ 203,372                  
Currency translation adjustment
                            42,340       42,340          
Other comprehensive income
                            513       513          
                                                 
Comprehensive income
                          $ 246,225                  
                                                 
Exercise of stock options, including tax benefit
    10       21,913                                  
Amortization of restricted stock compensation
            2,959                                  
Restricted stock award
    1       (1 )                             (405 )
Stock option expense
            5,011                                  
Stock acquired for cash
                                            (30,673 )
Stock sold in deferred compensation plan
            166                               71  
Fin 48 adjustment
                    (286 )                        
                                                 
Balance, December 31, 2007
  $ 522     $ 402,091     $ 690,713             $ 73,036     $ (81,535 )
Net income
                    222,710     $ 222,710                  
Currency translation adjustment
                            (101,365 )     (101,365 )        
Unrealized gain on marketable securities, net of tax (see Note 7)
                            2,028       2,028          
Reclassification adjustment, net of tax (see Note 7)
                            (2,028 )     (2,028 )        
Other comprehensive loss
                            (80 )     (80 )        
                                                 
Comprehensive income
                          $ 121,265                  
                                                 
Exercise of stock options, including tax benefit
    4       12,292                                  
Amortization of restricted stock compensation
            5,371                                  
Restricted stock award
                                            (863 )
Stock option expense
            5,537                                  
Stock acquired for cash
                                            (9,434 )
Stock sold in deferred compensation plan
            4                               1  
SEC stock issuance fee
            (11 )                                
                                                 
Balance, December 31, 2008
  $ 526     $ 425,284     $ 913,423             $ (28,409 )   $ (91,831 )
                                                 
 
The accompanying notes are an integral part of these financial statements.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net income
  $ 222,710     $ 203,372     $ 197,634  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    102,604       70,703       54,340  
Deferred income tax provision
    15,890       6,802       755  
Excess tax benefits from share-based payment arrangements
    (3,429 )     (8,127 )     (5,007 )
Non-cash gain on sale of workover services business
                (11,250 )
Loss on impairment of goodwill
    85,630              
Gains on sale of investment and disposals of assets
    (6,270 )     (14,883 )     (7,707 )
Equity in earnings of unconsolidated subsidiaries
    (2,983 )     (2,973 )     (7,148 )
Non-cash compensation charge
    10,908       7,970       7,595  
Other, net
    3,928       951       3,288  
Changes in operating assets and liabilities, net of effect from acquired businesses:
                       
Accounts receivable
    (155,897 )     (68,080 )     (88,429 )
Inventories
    (281,971 )     43,186       (22,569 )
Accounts payable and accrued liabilities
    143,479       34,806       (18,593 )
Taxes payable
    66,616       (7,199 )     11,621  
Other current assets and liabilities, net
    56,249       (18,629 )     22,837  
                         
Net cash flows provided by operating activities
    257,464       247,899       137,367  
Cash flows from investing activities:
                       
Capital expenditures, including capitalized interest
    (247,384 )     (239,633 )     (129,090 )
Acquisitions of businesses, net of cash acquired
    (29,835 )     (103,143 )     (99 )
Cash balances of workover services business sold
                (4,366 )
Proceeds from sale of investment
    27,381       29,354        
Proceeds from sale of buildings and equipment
    4,390       3,861       20,907  
Other, net
    (646 )     (1,275 )     (1,600 )
                         
Net cash flows used in investing activities
    (246,094 )     (310,836 )     (114,248 )
Cash flows from financing activities:
                       
Revolving credit borrowings (repayments)
    1,474       81,798       (6,617 )
Debt repayments
    (4,960 )     (6,972 )     (2,284 )
Issuance of common stock
    8,868       13,796       8,509  
Purchase of treasury stock
    (9,563 )     (35,458 )     (15,056 )
Excess tax benefits from share based payment arrangements
    3,429       8,127       5,007  
Payment of financing costs
    (39 )     (255 )     (580 )
Other, net
    (875 )     (404 )     (180 )
                         
Net cash flows provided by (used in) financing activities
    (1,666 )     60,632       (11,201 )
Effect of exchange rate changes on cash
    (9,802 )     5,018       1,350  
                         
Net increase (decrease) in cash and cash equivalents from continuing operations
    (98 )     2,713       13,268  
Net cash used in discontinued operations — operating activities
    (295 )     (517 )     (170 )
Cash and cash equivalents, beginning of year
    30,592       28,396       15,298  
                         
Cash and cash equivalents, end of year
  $ 30,199     $ 30,592     $ 28,396  
                         
 
The accompanying notes are an integral part of these financial statements.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED 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. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. The Company’s operations prior to 2001 were conducted by Oil States Industries, Inc. (OSI). On February 14, 2001, the Company acquired three companies (HWC Energy Services, Inc. (HWC); PTI Group, Inc. (PTI) and Sooner Inc. (Sooner)). All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying consolidated financial statements.
 
The Company, through its subsidiaries, is a leading provider of specialty products and services to oil and gas drilling and production companies throughout the world. It operates in a substantial number of the world’s active oil and gas producing regions, including the Gulf of Mexico, U.S. onshore, West Africa, the North Sea, Canada, South America and Southeast Asia. The Company operates in three principal business segments — well site services, offshore products and tubular services. The Company’s well site services segment includes the accommodations, rental tools and drilling services businesses.
 
2.   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, notes receivable, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our fixed rate contingent convertible senior notes, on the accompanying consolidated balance sheets approximate their fair values.
 
The fair value of our 23/8% contingent convertible senior notes is estimated based on prices quoted from third-party financial institutions. The carrying and fair values of these notes are as follows (in thousands):
 
                                         
    At December 31,  
    2008     2007  
    Interest
    Carrying
    Fair
    Carrying
    Fair
 
    Rate     Value     Value     Value     Value  
 
23/8% Contingent Convertible Senior Notes due 2025
    23/8 %   $ 175,000     $ 133,613     $ 175,000     $ 225,225  
                                         
 
As of December 31, 2008, the estimated fair value of the Company’s debt outstanding under its revolving credit facility is estimated to be lower than carrying value since the terms of this facility are more favorable than those that might be expected to be available in the current credit and lending environment. We are unable to estimate the fair value of the Company’s bank debt due to the potential variability of expected outstanding balances under the facility. Refer to Note 8 for terms of the Company’s credit facility.
 
Inventories
 
Inventories consist of tubular and other oilfield products, manufactured equipment, spare parts for manufactured equipment, raw materials and supplies and raw materials for remote accommodation facilities. Inventories include raw materials, labor, subcontractor charges and manufacturing overhead and are carried at the lower of cost or market. The cost of inventories is determined on an average cost or specific-identification method.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, for assets owned or recorded under capital lease, 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.
 
Goodwill
 
Goodwill represents the excess of the purchase price for acquired businesses over the allocated value of the related net assets after impairments, if applicable. Goodwill is stated net of accumulated amortization of $10.8 million at December 31, 2008 and $18.0 million at December 31, 2007. Accumulated amortization of goodwill decreased in 2008 compared to 2007 primarily as a result of goodwill impairment recognized in 2008.
 
We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. Impairment of goodwill is tested at the reporting unit level by comparing the reporting unit’s carrying amount, including goodwill, to the implied fair value (IFV) of the reporting unit. Our reporting units with goodwill remaining include offshore products, accommodations and rental tools, after the 100% impairment of goodwill associated with our tubular services and drilling reporting units discussed in Note 6 to these Consolidated Financial Statements. The IFV of the reporting units are estimated using primarily an analysis of trading multiples of comparable companies to our reporting units. We also utilize discounted projected cash flows and acquisition multiples analyses in certain circumstances. We discount our projected cash flows using a long term weighted average cost of capital for each reporting unit based on our estimate of investment returns that would be required by a market participant. If the carrying amount of the reporting unit exceeds its fair value, goodwill is considered impaired, and a second step is performed to determine the amount of impairment, if any. We conduct our annual impairment test in December of each year.
 
See Note 6 — Goodwill and Other Intangible Assets.
 
Impairment of Long-Lived Assets
 
In compliance with Statement of Financial Accounting Standards 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 representing substantially all of the balances within accumulated other comprehensive income. 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.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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. In the past, foreign exchange risk has also been 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. The Company had no currency contracts outstanding at December 31, 2008, December 31, 2007 or December 31, 2006. Net gains or losses from foreign currency exchange contracts that are designated as hedges would be recognized in the income statement to offset the foreign currency gain or loss on the underlying transaction. Exchange gains and losses associated with our operations have totaled $1.6 million gain in 2008, a $0.9 million loss in 2007 and a $0.4 million loss in 2006 and are included in other operating income.
 
Interest Capitalization
 
Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. There was no interest capitalized during the year ended December 31, 2008. For the years ended December 31, 2007 and December 31, 2006, $1.0 million and $0.1 million was capitalized, respectively.
 
Revenue and Cost Recognition
 
Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectibility is probable and pricing is fixed and determinable. Our product sales terms do not include significant post delivery obligations. For significant 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 contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. In drilling services and rental tool 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 or lost downhole are reflected as gains or losses on the disposition of assets. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.
 
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.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
In accounting for income taxes, we are required by the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48) to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
 
Receivables and Concentration of Credit Risk, Concentration of Suppliers
 
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.
 
The Company purchased 75% of its oilfield tubular goods from three suppliers in 2008, with the largest supplier representing 58% of its purchases in the period. The loss of any significant supplier in the tubular services segment could adversely affect it.
 
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, customer solvency 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 per share (EPS) amounts have been computed based on the average number of common shares outstanding, including 201,757 shares of common stock as of December 31, 2008 and 2007, 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. All shares of restricted stock awarded under the Company’s Equity Participation Plan are included in the Company’s basic and fully diluted shares as such restricted stock shares vest.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Diluted EPS amounts include the effect of the Company’s outstanding stock options under the treasury stock method. In addition, shares assumed issued upon conversion of the Company’s 23/8% Contingent Convertible Senior Subordinated Notes averaged 1,270,433 and 729,830 during the years ended December 31, 2008 and December 31, 2007, respectively, and are included in the calculation of fully diluted shares outstanding and fully diluted earnings per share.
 
Stock-Based Compensation
 
We adopted Statement of Financial Accounting Standards No. 123R (SFAS 123R) “Share-based Payment” effective January 1, 2006. This pronouncement requires companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. Prior to the adoption of SFAS 123R, this accounting treatment was optional with pro forma disclosures required. During the years ended December 31, 2008, December 31, 2007 and December 31, 2006, the Company recognized non-cash general and administrative expenses for stock options and restricted stock awards totaling $10.9 million, $8.0 million and $7.6 million, respectively. 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 13.
 
Guarantees
 
The Company applies FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Indebtedness of Others,” 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 ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are based on historical experience by product, configuration and geographic region. Changes in the warranty reserves were as follows (in thousands):
 
                 
    Year Ended December 31,  
    2008     2007  
 
Beginning balance
  $ 1,978     $ 1,656  
Provisions for warranty
    1,370       2,796  
Consumption of reserves
    (1,298 )     (2,510 )
Translation and other changes
    (84 )     36  
                 
Ending balance
  $ 1,966     $ 1,978  
                 
 
Current warranty provisions are typically related to the current year’s sales, while 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, 2008, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements was approximately $16.8 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.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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, estimate of the Company’s share of earnings from equity method investments, the valuation allowance recorded on net deferred tax assets, warranty, inventory and bad debt reserves. Actual results could differ from those estimates.
 
Discontinued Operations
 
Prior to our initial public offering in February 2001, we sold businesses and reported the operating results of those businesses as discontinued operations. Existing reserves related to the discontinued operations as of December 31, 2008 and 2007 represent an estimate of the remaining contingent liabilities associated with the Company’s exit from those businesses.
 
3.   Details of Selected Balance Sheet Accounts
 
Additional information regarding selected balance sheet accounts at December 31, 2008 and 2007 is presented below (in thousands):
 
                 
    2008     2007  
 
Accounts receivable:
               
Trade
  $ 456,975     $ 353,716  
Unbilled revenue
    119,907       97,579  
Other
    3,268       2,487  
                 
Total accounts receivable
    580,150       453,782  
Allowance for doubtful accounts
    (4,168 )     (3,629 )
                 
    $ 575,982     $ 450,153  
                 
 
                 
    2008     2007  
 
Inventories:
               
Tubular goods
  $ 396,462     $ 191,374  
Other finished goods and purchased products
    88,848       61,306  
Work in process
    65,009       56,479  
Raw materials
    68,881       47,737  
                 
Total inventories
    619,200       356,896  
Inventory reserves
    (6,712 )     (7,549 )
                 
    $ 612,488     $ 349,347  
                 
 


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
    Estimated
             
    Useful Life     2008     2007  
 
Property, plant and equipment:
                       
Land
          $ 18,298     $ 12,665  
Buildings and leasehold improvements
    3-50 years       135,080       107,954  
Machinery and equipment
    2-29 years       270,434       220,049  
Accommodations assets
    10-15 years       300,765       276,182  
Rental tools
    4-10 years       141,644       108,968  
Office furniture and equipment
    1-10 years       26,506       23,659  
Vehicles
    2-10 years       68,645       52,508  
Construction in progress
            49,915       43,046  
                         
Total property, plant and equipment
            1,011,287       845,031  
Less: Accumulated depreciation
            (315,949 )     (258,121 )
                         
            $ 695,338     $ 586,910  
                         
 
Depreciation expense was $99.0 million, $66.5 million and $50.5 million in the years ended December 31, 2008, 2007 and 2006, respectively.
 
                 
    2008     2007  
 
Accounts payable and accrued liabilities:
               
Trade accounts payable
  $ 307,132     $ 186,357  
Accrued compensation
    35,864       27,156  
Accrued insurance
    7,551       7,386  
Accrued taxes, other than income taxes
    7,257       3,733  
Reserves related to discontinued operations
    2,544       2,839  
Other
    11,441       11,648  
                 
    $ 371,789     $ 239,119  
                 
 
4.   Recent Accounting Pronouncements
 
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. We adopted those provisions of SFAS 157 that were unaffected by the delay in the first quarter of 2008. Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows. The Company does not have any material recurring fair value measurements.
 
In February 2007, the FASB issued SFAS No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company has chosen not to adopt the elective provisions of SFAS 159 for its existing financial instruments.
 
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for fiscal years beginning after December 15, 2008. Since SFAS 141R will be adopted prospectively, it is not possible to determine the effect, if any, on the Company’s results from operations or financial position.
 
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material impact on our results from operations or financial position.
 
In May 2008, the FASB issued FASB Staff Position (FSP) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which will change the accounting for our 23/8% Notes. Under the new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity will be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the new rules on our 23/8% Notes is that the equity component will be classified as part of stockholders’ equity on our balance sheet and the value of the equity component will be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense will result by recognizing the accretion of the discounted carrying value of the debt component of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application. In addition to a reduction of debt balances and an increase to stockholders’ equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $3 million, $5 million, $6 million and $6 million for 2005, 2006, 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $7 million, $7 million, $8 million and $4 million for 2009, 2010, 2011 and 2012, respectively. As of January 1, 2009, the amortized balance of the 23/8% Notes will be $149.1 million.
 
See also Note 10 — Income Taxes and Change in Accounting Principle for a discussion of the FASB’s Interpretation No. 48 — Accounting for Uncertainty in Income Taxes.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
5.   Earnings Per Share (EPS)
 
                         
    2008     2007     2006  
    (In thousands, except per share data)  
 
Basic earnings per share:
                       
Net income
  $ 222,710     $ 203,372     $ 197,634  
Weighted average number of shares outstanding
    49,622       49,500       49,519  
Basic earnings per share
  $ 4.49     $ 4.11     $ 3.99  
Diluted earnings per share:
                       
Net income
  $ 222,710     $ 203,372     $ 197,634  
Weighted average number of shares outstanding (basic)
    49,622       49,500       49,519  
Effect of dilutive securities:
                       
Options on common stock
    419       596       807  
23/8% Convertible Senior Subordinated Notes
    1,271       730       391  
Restricted stock awards and other
    102       85       56  
Total shares and dilutive securities
    51,414       50,911       50,773  
Diluted earnings per share
  $ 4.33     $ 3.99     $ 3.89  
 
6.   Goodwill and Other Intangible Assets
 
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. The Company had five reporting units as of December 31, 2008, prior to the 100% impairment of two of these reporting units’ goodwill amounts discussed below. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company would recognize an impairment charge for any amount by which the carrying amount of a reporting unit’s goodwill exceeds the unit’s fair value. The Company uses, as appropriate in the current circumstance, comparative market multiples, discounted cash flow calculations and acquisition comparables 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 reviewed 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. As of December 31, 2008, no provision for impairment of other intangible assets was required based on the evaluations performed.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Changes in the carrying amount of goodwill for the year ended December 31, 2008 and 2007 are as follows (in thousands):
 
                                 
    Well Site
    Offshore
    Tubular
       
    Services     Products     Services     Total  
 
Balance as of December 31, 2006
  $ 193,635     $ 75,716     $ 62,453     $ 331,804  
Goodwill acquired
    50,570                   50,570  
Foreign currency translation and other changes
    8,763       97       410       9,270  
                                 
Balance as of December 31, 2007
  $ 252,968     $ 75,813     $ 62,863     $ 391,644  
Goodwill acquired
    2,126       11,027             13,153  
Foreign currency translation and other changes
    (11,960 )     (1,766 )           (13,726 )
Goodwill impairment
    (22,767 )           (62,863 )     (85,630 )
                                 
Balance as of December 31, 2008
  $ 220,367     $ 85,074     $     $ 305,441  
                                 
 
SFAS 142 prescribes a two-step method for determining goodwill impairment. The Company has historically employed a trading multiples valuation method to determine fair value of its reporting units. Given the market turmoil caused by the global economic recession and credit market disruption in the second half of 2008, the Company augmented its valuation methodology to include discounted cash flow valuations of its reporting units based on the expected cash flows of such units. Based on a combination of factors (including the current global economic environment, the Company’s near term outlook for U.S. drilling activity, higher costs of equity and debt capital and the decline in market capitalization for the Company and comparable oilfield service companies), the Company concluded that the goodwill amounts previously recorded in the tubular services and drilling reporting units were impaired in their entirety. The total goodwill impairment charge recognized in the fourth quarter of 2008 was $85.6 million before taxes and $79.8 million after-tax. The majority of the impairment charge is related to goodwill recorded prior to or in conjunction with the Company’s initial public offering in 2001. This non-cash charge did not impact the Company’s liquidity position, its debt covenants or cash flows.
 
The portion of goodwill deductible for tax purposes totaled approximately $7.2 million at December 31, 2008. The following table presents the total amount assigned and the total amount amortized for major intangible asset classes as of December 31, 2008 and 2007 (in thousands):
 
                                 
    December 31, 2008     December 31, 2007  
    Gross Carrying
    Accumulated
    Gross Carrying
    Accumulated
 
    Amount     Amortization     Amount     Amortization  
 
Amortizable intangible assets Customer relationships
  $ 16,128     $ 1,560     $ 16,128     $ 486  
Non-compete agreements
    11,860       9,674       15,771       11,927  
Patents and other
    9,129       3,206       8,798       2,577  
                                 
    $ 37,117     $ 14,440     $ 40,697     $ 14,990  
                                 
 
Intangible assets, other than goodwill, are included within Other noncurrent assets in the Consolidated Balance Sheets. The weighted average remaining amortization period for all intangible assets, other than goodwill and indefinite lived intangibles, is 11.4 years and 11.8 years as of December 31, 2008 and 2007, respectively. Total amortization expense is expected to be $3.2 million, $2.3 million, $1.8 million, $1.7 million and $1.5 million in 2009, 2010, 2011, 2012 and 2013, respectively. Amortization expense was $3.6 million, $4.2 million and $3.9 million in the years ended December 31, 2008, 2007 and 2006, respectively.


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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
7.   Workover Services Business Transaction, Investment in Boots & Coots and Notes Receivable from Boots & Coots
 
Effective March 1, 2006, we completed a transaction to combine our workover services business with Boots & Coots International Well Control, Inc. (Boots & Coots) in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.2 million. Our workover services business was part of our well site services segment prior to the combination. The closing of the transaction resulted in a non-cash pretax gain of $20.7 million.
 
As a result of the closing of the transaction, we initially owned 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction bear a fixed annual interest rate of 10% and mature on September 1, 2010. See Note 17 — Subsequent Events. In connection with this transaction, we also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement. A shelf registration statement was finalized by Boots & Coots effective in the fourth quarter of 2006 and we sold shares in 2007 and 2008 as described below.
 
In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots common stock that it owned for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share, in the second quarter of 2007. After this sale of Boots & Coots shares and the sale of primary shares of stock directly by Boots & Coots in April 2007, our ownership interest in Boots & Coots was reduced to approximately 15%. We continued to use the equity method of accounting to account for the Company’s remaining investment in Boots & Coots common stock (11.5 million shares). The carrying value of the Company’s remaining investment in Boots & Coots common stock totaled $19.6 million as of December 31, 2007.
 
The Company sold an aggregate total of 11,512,137 shares of Boots & Coots stock representing the remaining shares that it owned in a series of transactions during May, June and August of 2008. The sale of Boots & Coots stock resulted in net proceeds of $27.4 million and a net after tax gain of $3.6 million, or approximately $0.07 per diluted share in the twelve months ended December 31, 2008. After June 30, 2008, our ownership interest in Boots & Coots was approximately 7%. As a result of this decreased ownership percentage, we reconsidered the method of accounting utilized for this investment and concluded that we should discontinue the use of the equity method of accounting since we no longer had the ability to significantly influence Boots & Coots. We, therefore, began to account for the remaining investment in Boots & Coots common stock (5.4 million shares at June 30, 2008) as an available for sale security as defined in Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” effective June 30, 2008. In accordance with SFAS No. 115, the carrying value of the remaining shares owned by the Company was adjusted to fair value through an unrealized after tax holding gain in the amount of $2.0 million recorded as other comprehensive income for the twelve months ended December 31, 2008. The sale of the remaining 5.4 million shares in August of 2008 resulted in the reclassification of the $2.0 million unrealized after tax gain from accumulated other comprehensive income into earnings for the twelve months ended December 31, 2008. The carrying value of the Company’s note receivable due from Boots & Coots (on September 2, 2010) is $21.2 million as of December 31, 2008 and is included in other non-current assets on the balance sheet. See Note 17 — Subsequent Events.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
8.   Long-term Debt
 
As of December 31, 2008 and 2007, long-term debt consisted of the following (in thousands):
 
                 
    2008     2007  
 
US revolving credit facility, with available commitments up to $325 million; secured by substantially all of our assets; commitment fee on unused portion ranged from 0.175% to 0.200% per annum in 2008 and 2007; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 3.9% for 2008 and 6.2% for 2007
  $ 226,000     $ 214,800  
Canadian revolving credit facility, with available commitments up to $175 million; secured by substantially all of our assets; variable interest rate payable monthly based on the Canadian prime rate or Bankers Acceptance discount rate plus applicable percentage; weighted average rate was 4.3% for 2008 and 5.4% for 2007
    61,244       89,060  
23/8% Contingent Convertible Senior Subordinated Notes due 2025
    175,000       175,000  
Subordinated unsecured notes payable to sellers of businesses, interest of 6%, maturing in 2008 and 2009
    4,500       9,000  
Capital lease obligations and other debt
    13,147       3,960  
                 
Total debt
    479,891       491,820  
Less: current maturities
    4,943       4,718  
                 
Total long-term debt
  $ 474,948     $ 487,102  
                 
 
Scheduled maturities of combined long-term debt as of December 31, 2008, are as follows (in thousands):
 
         
2009
  $ 4,943  
2010
    427  
2011
    291,862  
2012
    175,399  
2013
    304  
Thereafter
    6,956  
         
    $ 479,891  
         
 
The Company’s capital leases consist primarily of plant facilities, an office building and equipment. The value of capitalized leases and the related accumulated depreciation totaled $9.7 million and $0.9 million, respectively, at December 31, 2008. The value of capitalized leases and the related accumulated depreciation totaled $1.1 million and $0.5 million, respectively, at December 31, 2007.
 
23/8% Contingent Convertible Senior Notes
 
In June, 2005, we sold $125 million aggregate principal amount of 23/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the SEC’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.
 
The notes are senior unsecured obligations of the Company and bear interest at a rate of 23/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. We have assumed


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the redemption of the notes at the date of the note holders first optional redemption date in 2012 in our schedule of debt maturities above. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were included in the calculation of diluted earnings per share during periods when our average stock price exceeded the initial conversion price of $31.75 per share. The terms of the notes require that our stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price (or $38.10 per share) for at least 20 trading days in a defined period before the notes are convertible. If a note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they would receive cash up to $1,000 for each 23/8% note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 23/8% notes of 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 23/8% Notes for conversion. In connection with the note offering, the Company agreed to register the notes within 180 days of their issuance and to keep the registration effective for up to two years subsequent to the initial issuance of the notes. The notes were so registered in November 2005. The maximum amount of contingent interest that could potentially inure to the note holders during such time period is not material to the consolidated financial position or the results of operations of the Company.
 
Revolving Credit Facility
 
On December 13, 2007, we exercised the accordion feature available under our Credit Agreement dated October 30, 2003, as amended. The Company’s credit facility currently totals $500 million of available commitments. Under this senior secured revolving credit facility with a group of banks, up to $175 million is available in the form of loans denominated in Canadian dollars and may be made to the Company’s principal Canadian operating subsidiaries. The facility matures on December 5, 2011. 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 0.5% to 1.25%; or
 
  •  an alternate base rate equal to the higher of the bank’s prime rate and the federal funds effective rate (or, in the case of Canadian dollar denominated loans, the Canadian Prime Rate).
 
Commitment fees ranging from 0.175% to 0.25% 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 Agreement, which governs our credit facility, contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt, to consolidated EBITDA of no greater than 3.25 to 1.0 in 2009 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2008, we were in compliance with our debt covenants. The credit facility also contains negative covenants that limit the Company’s ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.


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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 April 7, 2008, we had $287.2 million outstanding under this facility and an additional $16.8 million of outstanding letters of credit leaving $196.0 million available to be drawn under the facility.
 
On January 11, 2005 the Company renewed its overdraft credit facility providing for borrowings totaling £2.0 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, 2008. Letters of credit totaling £0.7 million were outstanding as of December 31, 2008, leaving £1.3 million available to be drawn under this facility.
 
A subsidiary of the Company maintains an additional revolving credit facility with a bank. A total of $4.2 million was outstanding under this facility as of December 31, 2008. This facility consists of a swing line with a bank, borrowings under which are used for working capital efficiencies.
 
9.   Retirement Plans
 
The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $8.4 million, $6.1 million and $5.4 million, respectively, related to its various defined contribution plans during the years ended December 31, 2008, 2007 and 2006, respectively.
 
10.   Income Taxes
 
Consolidated pre-tax income for the years ended December 31, 2008, 2007 and 2006 consisted of the following (in thousands):
 
                         
    2008     2007     2006  
 
US operations
  $ 225,846     $ 183,242     $ 206,288  
Foreign operations
    153,214       117,116       95,359  
                         
Total
  $ 379,060     $ 300,358     $ 301,647  
                         
 
The components of the income tax provision for the years ended December 31, 2008, 2007 and 2006 consisted of the following (in thousands):
 
                         
    2008     2007     2006  
 
Current:
                       
Federal
  $ 94,082     $ 58,753     $ 69,849  
State
    5,097       3,564       4,172  
Foreign
    37,639       29,754       30,193  
                         
      136,818       92,071       104,214  
                         
Deferred:
                       
Federal
    12,378       1,172       3,017  
State
    1,320       33       (762 )
Foreign
    5,833       3,710       (2,456 )
                         
      19,531       4,915       (201 )
                         
Total Provision
  $ 156,349     $ 96,986     $ 104,013  
                         


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The provision for taxes differs from an amount computed at statutory rates as follows for the years ended December 31, 2008, 2007 and 2006 (in thousands):
 
                         
    2008     2007     2006  
 
Federal tax expense at statutory rates
  $ 132,671     $ 105,125     $ 105,576  
Foreign income tax rate differential
    (10,570 )     (6,802 )     (2,880 )
Reduced foreign tax rates
          (1,088 )     (2,168 )
Nondeductible goodwill
    24,317              
Other nondeductible expenses
    2,586       1,411       149  
State tax expense, net of federal benefits
    3,879       2,338       2,051  
Domestic manufacturing deduction
    (1,212 )     (2,435 )     (872 )
FIN 48 adjustments
    2,868       (1,751 )      
Dividend income — foreign affiliate
                1,542