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, 2009

Commission file no. 1-16337

Oil States International, Inc.

(Exact name of registrant as specified in its charter)

 

 

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:

 

 

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)  YES o 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):

 

 

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, 2009)		$	1,203,768,904

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:

 

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s Definitive Proxy Statement for the 2010 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

 

 

This Annual Report on Form 10-K contains “certain 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.

 

In any forward-looking statement, where 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:

 

 

 

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 Canada, onshore and offshore U.S., West Africa, the North Sea, South America and Southeast and Central Asia. Our customers include many of the national oil companies, major and independent oil and gas companies, onshore and offshore drilling companies

and other oilfield service companies. We operate in three principal business segments — well site services, offshore products and tubular 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 filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. 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 to the corporate secretary at the address shown on the cover page of this Form 10-K.

 

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), Oil States Energy Services, Inc. (OSES) formerly known as HWC Energy Services, Inc., 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, OSES, PTI and Sooner would merge with wholly owned subsidiaries of Oil States (the Combination). As a result, OSES, 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 expect we can expand market share and where we believe we can achieve an attractive return on our investment. Currently, we see investment opportunities in the oil sands developments in Canada, in shale play regions in North America and in the expansion of our capabilities to manufacture and assemble deepwater capital equipment on a global basis. Current global economic conditions have improved compared to those experienced in the past year; however, activity in the markets we serve have not returned to levels seen prior to the recent market disruption. As part of our long-term growth strategy, notwithstanding that in 2009 we did not make any significant acquisitions as a result of our inability to find transactions at appropriate prices that met our acquisition criteria, we continue to review complementary acquisitions as well as organic capital expenditures to enhance our cash flows. For additional discussion of our business strategy, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Capital Spending and Acquisitions

 

Capital spending since our initial public offering in February 2001 has totaled $981.5 million and has included both growth and maintenance capital expenditures in each of our businesses as follows: Accommodations — $471.2 million, Rental Tools — $225.3 million, Drilling and Other — $178.9 million, Offshore Products — $93.3 million, Tubular Services — $9.4 million and Corporate — $3.4 million.

Since the completion of our initial public offering in February 2001, we have completed 36 acquisitions for total consideration of $499.6 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 allowed us to expand our geographic locations and our product and service offerings. This growth strategy has allowed us to leverage our existing and acquired products and services into new geographic locations, and has expanded our technology and product offerings. We have made strategic acquisitions in offshore products, tubular services and in our well site services business lines.

 

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 our well site services segment, we purchased all of the equity of an accommodations lodge in the Conklin area of Alberta, Canada. In our offshore products segment, we acquired a waterfront manufacturing facility on the Houston ship channel.

 

In 2009, we acquired the 51% majority interest in a venture we had previously accounted for under the equity method. The acquired business supplies accommodations and other services to mining operations in Canada. Consideration paid for the business was $2.3 million in cash and estimated contingent consideration of $0.3 million. The operations of this business have been included in the accommodations business within the well site services segment.

 

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 the exploration for and development of oil and natural gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. See Note 14 to the 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. However, this past year saw broad-based declines in oil and natural gas prices, together with constrained capital and credit markets associated with the global economic recession, which resulted in a decline in spending and activity by our customers in most of our business segments during 2009. For additional information about activities in each of our segments, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

Two of our well site services businesses (drilling and rental tools) are significantly affected by the North American rig count. Activity increased during 2005 and 2006, had relatively flat year-over-year activity in 2007, reached peak activity levels during 2008, but saw material declines beginning in the fourth quarter of 2008, which in most of our businesses, continued through the third quarter of 2009. Activity levels have improved off their

2009 troughs. In particular, oil and horizontal drilling activities have substantially recovered and are now near peak activity levels attained prior to the downturn; however, pricing for work has not recovered to prior peak levels. By year end 2009, the drilling and rental businesses had generally stabilized. Increased activity supporting oil sands developments in northern Alberta, Canada by our accommodations business has had an offsetting 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 significantly increased backlog and revenues from 2004 to 2008, which resulted in improved operating results during 2005, 2006, 2007 and in 2008. Backlog began declining in the fourth quarter of 2008 and continued to decline throughout 2009 due to project postponements, cancellations and deferrals which limited new order activity. However, the high level of backlog entering the year provided stability in revenues and profits in 2009. Bidding activity appears to be improving in early 2010.

 

Our tubular services business is influenced by U.S. drilling activity similar to certain business lines in our well site services segment and has historically been our most cyclical business segment. 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. In 2009, OCTG prices declined precipitously putting significant downward pressure on pricing and margins. These price declines coupled with weaker demand for OCTG, caused by the decline in U.S. drilling in 2009, led to significantly lower profits for our tubular services business in 2009.

 

Well Site Services

 

Overview

 

During the year ended December 31, 2009, we generated approximately 37% of our revenue and 50% of our operating income, excluding the goodwill impairment recognized during the year and 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 drill for, establish and maintain the flow of oil and natural gas from a well throughout its lifecycle and to accommodate personnel in remote locations. Our operations include land drilling services, remote site accommodations and rental tools. We use our fleet of drilling rigs, rental equipment and 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 accommodations are employed to support work forces in the Canadian oil sands and in 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 our accommodations supporting conventional drilling activities has historically been tied to the level of oil and natural gas exploration and production activity. 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.

 

Our accommodations business has grown in recent years due to the increasing demand for accommodations to support workers in the oil sands region of Canada. Demand for oil sands accommodations is influenced to a greater extent by the longer-term outlook for energy prices, particularly crude oil prices, given the multi-year time frame to complete oil sands projects and the costs associated with development of such large scale projects. However, full utilization of our existing accommodations capacity as a result of our current and future expansions of our accommodations facilities will largely depend on continued oil sands development spending.

 

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 15,000 feet. Drilling services are typically used during the exploration and development stages of a field. As of December 31, 2009, we had a total of 37 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 75,000 to

500,000 pounds, 14 of which were fabricated and/or assembled in our Odessa, Texas facility with components purchased from specialty vendors. Twenty-three 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 of our drilling rigs decreased from an average of 82.4% in 2008 to an average of 36.7% in 2009. On December 31, 2009, 23 of our rigs were working or under contract with utilization of approximately 62%.

 

We market our drilling services directly to a diverse customer base, consisting of major, independent and private oil and gas companies. We contract on both footage and dayrate basis and have two rigs in West Texas operating under multi-well turnkey contracts. Under a footage or turnkey drilling contract, we assume responsibility for certain costs (such as bits and fuel) and assume more risk (such as time necessary to drill) than we would on a daywork contract. 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. Our Permian Basin drilling activities target primarily oil reservoirs while our Rocky Mountain drilling activities target primarily natural gas reservoirs.

 

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:

 

 

Our rental equipment is primarily used during the completion and production stages of a well. As of December 31, 2009, we provided rental equipment at 64 distribution points throughout the United States, Canada, Mexico and Argentina, compared to 72 distribution points at December 31, 2008. We consolidated certain of our rental tool operations in 2009, closing eight locations; we are currently further combining some of these distribution points to streamline operations, enhance our facilities 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 the larger oilfield service companies, who are at times also our customers for certain products and services. The concentration of customer activity in shale natural gas reserve areas in North America, coupled with the overall decline in the rig count, has led to equipment excesses which have intensified competition for our products and services in those areas.

 

Accommodations.  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 work force accommodations where traditional hotels and infrastructure are not accessible or cost effective. Once facilities are deployed in the field, we can 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 camps range in size from a 25 person drilling camp to a 2,000 person camp supporting varied operations, including pipeline construction, Steam Assisted Gravity Drainage (“SAGD”) drilling operations and large shale oil projects.

 

We own two accommodations manufacturing plants near Edmonton, Alberta, Canada which specialize in the design, engineering, production, transportation and installation of a variety of portable modular buildings, both for third parties and for our own use. We manufacture facilities to suit the climate, terrain and population of a specific project site.

 

Our accommodations business is focused primarily in northern Canada, but also operates in the U.S. Rocky Mountain corridor (Wyoming, Colorado, North Dakota), the 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 natural gas. To a lesser extent, we also operate in other industries, including pipeline construction, mining, forestry, humanitarian aid and disaster relief, and support for military operations. Our primary competitors in Canada include Aramark Corporation, Compass Group PLC, ATCO Structures and Logistics Ltd., Black Diamond Group Limited 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 $388.5 million, or 47.1%, 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 natural gas drilling has decreased, we have shifted certain accommodations assets, formerly used in support of conventional drilling activities, to support increasing demand in the oil sands. Oil sands related accommodations revenues have increased from 32.9% of total accommodations revenues in 2005 to 75.1% in 2009.

 

Since mid year 2006, we have installed over 5,400 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, 2009, these company-owned properties include PTI Beaver River Executive Lodge (732 rooms), PTI Athabasca Lodge (1,537 rooms), PTI Wapasu Creek Lodge (2,648 rooms) and PTI Conklin Lodge (518 rooms). We are currently expanding the capacity of our PTI Wapasu Creek Lodge to over 4,100 rooms by the end of 2010.

 

Offshore Products

 

Overview

 

During the year ended December 31, 2009, we generated approximately 24% of our revenue and 33% of our operating income, excluding the goodwill impairment recognized in our rental tool operations during the period and 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 supply other lower margin products and services such as fabrication and inspection services. Our products and services are used primarily in deepwater producing regions and include flex-element technology, advanced connector systems, blow-out preventer 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 natural gas and related drilling and production in offshore areas throughout the world, particularly in deeper water, will drive spending on these activities.

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 natural 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.

 

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 natural gas wells on offshore fixed platforms and mobile production units, including floating platforms, such as Spars and tension leg platforms, and floating production, storage and offloading (FPSO) vessels, and on other marine vessels, floating rigs and jack-up rigs. Our products and services include:

 

 

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 weld-on connectors 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 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 for the hydrocarbons from the subsea wellhead to the floating production platform. Oil and natural 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 efficiently assemble the tethers during offshore installation. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. An FPSO is a floating vessel, typically ship shaped, used to produce, and process oil and gas from subsea wells. 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 equipment used in the construction, maintenance, expansion and repair of offshore oil and natural gas pipelines. New construction equipment includes:

 

 

 

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:

 

 

Marine Winches, Mooring and Lifting Systems and Rig Equipment.  We design, engineer and manufacture marine winches, mooring and lifting systems and rig equipment. Our Skagit^® winches are specifically designed for mooring floating and semi-submersible drilling rigs and positioning pipelay and derrick barges, anchor handling boats and jack-ups, while our Nautilus^® marine cranes are used on production platforms throughout the world. We also design and fabricate rig equipment such as automatic pipe racking and blow-out preventor handling equipment. Our engineering teams, manufacturing capability and service technicians who install and service our products provide our customers with a broad range of equipment and services to support their operations. Aftermarket service and support of our installed base of equipment to our customers is also an important source of 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.

 

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:

 

 

Backlog.  Backlog in our offshore products segment was $206.3 million at December 31, 2009, compared to $362.1 million at December 31, 2008 and $362.2 million at December 31, 2007. We expect in excess of 85% of our backlog at December 31, 2009 to be completed in 2010. Bidding activity has increased recently; however, it has not yet resulted in firm customer orders yielding an overall increase in our backlog. 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. Our backlog is an important indicator of future offshore products shipments and revenues; however, 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, 2009, we generated approximately 39% of our revenue and 17% of our operating income, excluding the goodwill impairment recognized in our rental tool operations during the period and before corporate charges, from our tubular services segment. Through this segment and our Sooner, Inc. subsidiary, we distribute 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:

 

 

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 2009, we purchased 53% of our total tubular good volumes from a single domestic supplier and 71% of our total OCTG purchases from three domestic suppliers.

 

OCTG Market

 

Our tubular services segment primarily distributes casing and tubing. Casing forms the structural wall in oil and natural 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 natural 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 generally 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 have distribution relationships with most major domestic and certain international steel mills. 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 business segments. We operate our tubular services segment from a total of eight offices and facilities located near areas of oil and natural gas exploration and development activity, with a ninth facility planned to commence operations in Pennsylvania in 2010 to service the Marcellus shale area.

 

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.

 

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 31 developed acres and is serviced by a rail spur. Our Searcy location has approximately 140 pipe racks on 14 acres. Independent third party inspection companies operate within each of these facilities either with mobile or permanent inspection equipment.

 

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.

 

Suppliers and Competitors

 

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, 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 accommodations 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 second quarter and adversely affects our operations and sales of products and services. 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 natural 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, 2009, we had 5,474 full-time employees, 30% of whom are in our offshore products segment, 67% of whom are in our well site services segment (37% in accommodations, 23% in rental tools and 7% in drilling services), 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 964 employees located in Canada, the United Kingdom and Argentina as of December 31, 2009. We believe relations with our employees are good.

 

Government Regulation

 

Our business is significantly affected by foreign, federal, state and local laws and regulations relating to the oil and 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 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 stringent and comprehensive 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 existing environmental laws and regulations and we do not anticipate that future 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 with these existing requirements 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 currently are exempt from treatment as hazardous wastes under RCRA because that act specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas from regulation as hazardous waste. However, these 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. In any event, such wastes may remain subject to regulation under RCRA as solid wastes.

 

With regard to our U.S. operations, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known 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, strict 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 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 natural 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.

 

A certain portion of our rental tools business supports other contractors actually performing hydraulic fracturing to enhance the production of natural gas from formations with low permeability, such as shales. Due to concerns raised concerning potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated in the United States to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on

natural gas production activities by operators or other contractors with whom we have a business relationship, which in turn could have an adverse effect on the well site services that we provide to those operators.

 

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.

 

Past scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or “GHG” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. 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, which requires Canada to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. The Canadian federal government previously released the Regulatory Framework for Air Emissions, updated March 10, 2008 by Turning the Corner: Regulatory Framework for Industrial Greenhouse Emissions (collectively, the “Regulatory Framework”) for regulating GHG emissions and in doing so proposed mandatory emissions intensity reduction obligations on a sector by sector basis. Legislation to implement the Regulatory Framework had been expected to be put in place this year, but the federal government has delayed the release of any such regulation, and potential federal requirements in respect of GHG emissions are unclear.

 

On January 29, 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen. The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations is currently uncertain. Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 per cent reduction from 2005 levels by 2020, and the Canadian federal government has also indicated an objective of reducing overall Canadian GHG emissions by 60% to 70% by 2050. Additionally, in 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North America-wide cap and trade system for GHG emissions, in cooperation with the United States. Under the system, Canada would have a cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits. It is uncertain whether either federal GHG regulations or an integrated North American cap-and-trade system will be implemented, or what obligations might be imposed under any such systems.

 

Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets, and a company can meet the applicable emissions limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” by making payments of $15 per ton of GHG emissions to the Alberta Climate Change and Management Fund. The Alberta government recently announced its intention to raise the price of fund credits. The Specified Gas Reporting Regulation imposes GHG emissions reporting requirements if a company has GHG emissions of 100,000 tons or more from a facility in a year. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in permits and under other environmental regulations. The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. The direct and indirect costs of these regulations may adversely affect our operations and financial results as well as those of our customers.

 

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. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an

economy-wide cap-and-trade program to reduce U.S. emissions of GHGs. ACESA would require a 17% reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as coal, oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. The U.S. submitted an emission reduction target pursuant to the Copenhagen Accord process in “the range of” 17% below 2005 levels by 2020 (this target is subject to Congressional action). Moreover, nearly half of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs.

 

On December 15, 2009, the EPA published its findings that GHG emissions present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources, such as power plants and industrial sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including sources emitting more than 25,000 tons of GHGs on an annual basis, beginning in 2011 for emissions occurring in 2010. This coverage of this rule soon may be expanded to include oil and natural gas operations. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that our customers produce, which could in turn adversely impact the demand for our services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

 

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 with existing requirements 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.

 

 

Our Business is Subject to a Number of Economic Risks

 

Financial markets worldwide experienced extreme disruption in the past two years, 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 took unprecedented actions intended to address extreme market conditions such as severely restricted credit and declines in real estate values. We did not suffer an impairment of our borrowing ability during the economic disruption last year. However, such economic events can reoccur and can potentially affect businesses such as ours in a number of ways. Tightening of credit in financial markets and a slowing economy adversely affects the ability of our customers and suppliers to obtain financing for significant operations, can result 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 our receivables. Additionally, tightening of credit in financial markets coupled with a slowing economy could

negatively impact our cost of capital and ability to grow. Our business is also adversely affected when energy demand declines as a result of lower overall economic activity. Typically, lower energy demand negatively affects commodity prices which reduces the earnings and cash flow of our E&P customers, reducing their spending and demand for our products and services. These conditions could have an adverse effect on our operating results and our 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.

 

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 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 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 would 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. 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 natural gas and therefore influence product prices, including:

 

 

 

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.

 

Two of our businesses, where we manufacture offshore products for deepwater exploration and production and where we supply accommodations for oil sands, typically support our customers’ projects that are more capital intensive and take longer to generate first production than traditional oil and natural gas exploration and development activities. The economic analyses conducted by exploration and production companies in deepwater and oil sands areas have historically assumed a relatively conservative longer-term price outlook for production from such projects to determine economic viability. Perceptions of lower longer-term oil prices by these companies can cause our customers to 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 and natural gas prices have been and are expected to remain volatile. This volatility causes oil and gas companies and drilling contractors to change their strategies and expenditure levels. Supplies of oil and natural gas can be influenced by many factors, including improved technology such as the hydraulic fracturing of horizontally drilled wells in shale discoveries, access to potential productive regions and availability of required infrastructure to deliver production to the marketplace. We have experienced in the past, and expect to experience in the future, 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, 2009, goodwill represented approximately 11% 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 reporting units. In the second quarter of 2009, we recognized an impairment of $94.5 million representing a portion of our remaining goodwill as a result of several factors affecting our rental tools reporting unit. It is possible that we could recognize additional goodwill impairment charges if, among other factors:

 

 

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.

 

Although imports of OCTG from China are currently restricted by trade sanctions imposed by the U.S. government, lower-cost tubular goods from a number of foreign countries are still imported into the U.S. tubular goods market. If the level of imported lower-cost tubular goods were to otherwise increase from current levels, 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 those 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 2009, we purchased 53% of our total tubular goods from a single domestic supplier and 71% of our total OCTG purchases from three domestic suppliers. 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 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. During 2009, we experienced precipitous declines in both utilization and pricing in our drilling and rental tool segments given the material decline in the North American rig count over the period.

 

In addition, we have significantly increased our accommodations capacity in the oil sands region over the past five 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, or activity in the oil sands declines significantly, demand for our accommodations could decrease, negatively impacting the profitability of our well site services segment.

 

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 northern Alberta, Canada, 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 31% (8.9% excluding Canada) of our consolidated revenue in the year ended December 31, 2009. Risks associated with our operations in foreign areas include, but are not limited to:

 

 

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. While many countries have adopted similar anti-bribery statutes, there has not been universal adoption and enforcement of such statutes. Therefore, 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 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. We have already experienced high demand and increased wages for labor forces serving our well site services segment, notably in our accommodations business in Canada. When these events occur, our cost structure increases and our growth potential could be impaired.

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 growth 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 these intended benefits. 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:

 

 

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 shareholders of the Company 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 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:

 

 

 

We may be exposed to certain regulatory and financial risks related to climate change.

 

Climate change is receiving 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. A significant focus is being made on companies that are active producers of depleting natural resources.

 

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, provincial 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:

 

 

Any adoption by U.S. federal, regional or state governments mandating a substantial reduction in greenhouse gas emissions and implementation of the Kyoto Protocol or other federal or provincial requirements by the Governments of Canada or its provinces 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.

 

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our services.

 

The federal Congress is currently considering two companions bills in the United States, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or FRAC Act, that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in formations with low permeabilities, such as shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing

process could make it more difficult to complete natural gas wells in certain formations, increase our costs of compliance, and adversely affect the demand for the well site services that we provide.

 

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:

 

 

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.

 

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, equipment and service quality, availability, responsiveness, experience, technology, safety performance 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.

We have a significant concentration of our accommodations business located in the oil sands region of Alberta, Canada.

 

Because of the concentration of our accommodations business in the Canadian oil sands in one relatively small geographic area, we have increased exposure to political, regulatory, environmental, labor, climate or natural disaster events or developments that could negatively impact our operations and financial results.

 

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 (2009 low of $11.14 per share; 2009 high of $40.27 per share) 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, some customer contracts stipulate consequential damages payable, generally as a result of our gross negligence or willful misconduct. The final delivered products may also 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-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. In fulfilling some contracts, we provide limited warranties for our products. Although we estimate and record a provision for potential warranty claims, repair or replacement costs under warranty provisions in our contracts could exceed the estimated cost to cure the claim which could be material to our financial results. We utilize percentage completion accounting, depending on the size of a project and variations from estimated contract performance could have a significant impact on our reported operating results as we progress toward completion of major jobs.

 

Our backlog is subject to unexpected adjustments and cancellations and is, therefore, an imperfect 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 accommodations 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 natural 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 enough 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.

 

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 natural 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 water depths, higher pressure levels 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 declined sharply, and the credit markets and availability of credit were constrained. Additionally, many of our customers’ equity values 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 could have an adverse impact on our operating results and could adversely affect our liquidity.

 

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 889 employees in Canada, 60 employees in the United Kingdom and 15 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.

Currently proposed legislative changes could materially, negatively impact the Company, increase the costs of doing business and the demand for our products.

 

The current U.S. administration and Congress have proposed several new articles of legislation or legislative and administration changes which could have a material negative effect on our Company. Some of the proposed changes that could negatively impact us are:

 

 

 

None.

 

 

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.

 

 

We have six tubular sales offices and a total of 64 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.

 

 

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.

 

 

No matters were submitted to a vote of security holders during the fourth quarter of 2009.

 

 

Common Stock Information

 

Our authorized common stock consists of 200,000,000 shares of common stock. There were 49,859,479 shares of common stock outstanding as of February 16, 2010, including 101,757 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 16, 2010 was 33. 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 16, 2010 was $36.76 per share.

 

The following table sets forth the range of high and low sales prices of our common stock.

 

 

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. For additional discussion of such restrictions, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 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.

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, 2004 to December 31, 2009. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2004 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

 

 

Oil States International — NYSE

 

 

 

Copyright ^© 2010, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm

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

 

None.

 

 

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, 2009. The following data should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Company’s financial statements, and related notes included in Item 8, Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

 

Selected Financial Data
(In thousands, except per share amounts)

 

 

 

 

 

 

 

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):

 

 

 

 

 

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 natural 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. In contrast, portions of our accommodations activities supporting oil sands developments are more tied to the long-term outlook for crude oil prices. Our offshore products segment provides highly engineered and technically designed products for offshore oil and natural 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 overall industry 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, accommodations and rental tools. Demand for our drilling services is driven by land drilling activity in our primary drilling markets in West Texas, where we primarily drill oil wells, and in the Rocky Mountains area in the U.S. where we primarily drill natural gas wells. Our rental tools and services depend primarily upon the level of drilling, completion and workover activity in North America.

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, land drilling and rental tool businesses is highly correlated to changes in the drilling rig count in the United States and, to a much lesser extent, Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.

 

 

The average North American rig count for the year ended December 31, 2009 decreased by 950 rigs, or 42%, compared to the average for the year ended December 31, 2008. The rig count began to decline in the fourth quarter of 2008 and fell precipitously in the first half of 2009. However, the rig count began to recover in the latter part of 2009 and the rate of increase has accelerated in early 2010 with a rig count of approximately 1,897 rigs working in North America, including 1,346 working in the U.S. as of February 12, 2010.

 

Beginning in late 2008 and into 2009, we saw unprecedented declines in the global economic outlook that were initially fueled by the housing and credit crises. These market conditions led to reduced growth, and in some instances, decreased overall output. Market factors suggest that economic improvement is underway; however, the pace of improvement has been slow, and it is uncertain whether there will be sustained long-term growth. In addition, unemployment in the United States remains at relatively high levels. Although energy prices have recently increased off the low levels witnessed in the first half of 2009, our businesses have been and we expect will continue to be negatively impacted by excess equipment and service capacity given reduced activity levels relative to the 2008 peak. Given our customers’ decreased cash flows caused by comparatively lower energy prices as well as shrinking credit availability affecting some of them, funds available for exploration and development have been reduced substantially when compared to 2008. Although we believe our Company remains financially strong with low debt, significant undrawn revolver capacity and cash on hand, certain of our operations have been materially adversely affected by the reduced rig count in the North American energy sector. We experienced a significant decline in the utilization of our land drilling rigs beginning in late 2008 and continuing through the first half of 2009, with rig utilization improving somewhat in late 2009. In addition, in many instances, our customers have delayed or cancelled exploration and development plans and have sought pricing concessions from us.

 

An additional important factor in our business, particularly in our land based North American businesses, has been the successful development of several natural gas shale discoveries which we support through our rental tool and OCTG businesses. Much of the continuing exploration and development activity has focused in these shale areas leading us and many of our competitors to relocate equipment to and also concentrate on these areas. This has led to increased competition and significantly lower pricing. Domestic U.S. natural gas prices have decreased from a peak of approximately $13.00 per Mcf in July 2008 to recent levels of approximately $5.00 to $5.50 per Mcf. Many analysts are expecting continued weakness in natural gas prices unless reduced drilling activity and/or forced production shut-ins reverse natural gas supply excesses or demand for the commodity increases, which may occur if the economy were to strongly recover. There is also the risk that, as a result of the success of exploration and development activities in the shale areas coupled with the availability of increasing amounts of LNG, the supply of natural gas will offset or mitigate the impact of natural gas shut-ins or demand increases resulting from improved economic conditions. Neither the rig count nor commodity prices, especially for natural gas, are currently expected to recover to levels reached during peak activity levels in 2008 in the immediate future.

 

During 2009, we markedly reduced our expectations for the level of North American drilling activity, which is the primary driver of our rental tools utilization and pricing. We considered the factors driving these diminished expectations, among others, in assessing goodwill for potential impairment. As a result of our assessment, we wrote off a total of $94.5 million, or $81.2 million after tax, of goodwill in our rental tools reporting unit in the second

quarter of 2009. See Note 6 to the Consolidated Financial Statements included in this Annual Report on Form 10-K. Should conditions related to our rental tools reporting unit deteriorate further, we could potentially write off all or part of that reporting unit’s remaining goodwill balance of $74.8 million.

 

Crude oil prices fell to approximately $30 to $35 per barrel during the quarter ended March 31, 2009; however, oil prices have since recovered to levels of approximately $70 to $75 per barrel. Although significantly improved, crude oil prices remain far below the all time high closing price of $147 per barrel reached in July 2008. The current level of crude oil prices has led to a recovery of oil-related drilling activity in the United States and the sanctioning of some oil sands development projects in Canada. The oil rig count now exceeds peak levels reached during 2008. However, pricing power lost during 2009 in our drilling operations has not yet recovered. It is unknown whether crude oil prices will stabilize at levels that will continue to support significant levels of exploration and production because crude oil market demand fundamentals remain weak and inventories for the resource are high. Natural gas prices followed a similar recession-induced downturn. After peaking at $13.31 mmBtu in July 2008, Henry Hub natural gas prices fell approximately 50%. However, unlike the recovery of oil prices, natural gas prices have remained relatively depressed due in part to the excess supply of natural gas inventories. These market conditions sharply curtailed investment in exploration and development activities in North America during 2009 and may similarly affect demand in 2010 and 2011.

 

For the year 2009, the Canadian dollar was valued at an average exchange rate of U.S. $0.88 compared to U.S. $0.94 for 2008, a decrease of 6%. This weakening of the Canadian dollar had a significant negative impact on the translation of earnings generated from our Canadian subsidiaries. In January 2010, the value of the Canadian dollar strengthened to an average exchange rate of $0.96.

 

The major U.S. steel mills increased OCTG prices during 2008 because of high product demand, overall tight supplies and in response to raw material and other cost increases. However, steel prices on a global basis declined precipitously during the recession in 2009 and industry OCTG inventories increased materially as the rig count declined and imports remained at high levels. The developments in the OCTG marketplace had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during 2009 in our tubular services segment. However, these negative trends have moderated recently. The OCTG Situation Report suggests that industry OCTG inventory levels peaked in the first quarter of 2009 at approximately twenty months’ supply on the ground and have trended down to approximately nine months’ supply currently as the U.S. mills have materially reduced output, imports of OCTG have declined, particularly Chinese imports given the imposition of tariffs, and drilling activity has increased.

 

We continue to monitor the fallout of the financial crisis 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 reduced our capital spending significantly in 2009 compared to 2008. Capital expenditures in 2009 totaled $124.5 million compared to 2008 capital expenditures of $247.4 million. Our 2009 capital expenditures included funding to complete projects in progress at December 31, 2008, including (i) expansion of our Wapasu Creek accommodations facility in the Canadian oil sands, (ii) international expansion at offshore products and (iii) ongoing maintenance capital requirements. 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 remain focused on industry inventory levels, future drilling and completion activity and OCTG prices. In response to industry conditions and our corresponding decreased revenues, we have implemented a variety of cost saving measures throughout our businesses, including headcount reductions and a decrease in overhead costs.

 

There are several potential energy policy changes in Washington D.C. that will likely change how energy in the United States is produced and consumed. Some of the major proposed policy changes (which will not likely take effect or have a material impact in the near-term) focus on creating energy standards and efficiencies, provide financing for clean energy generation, and emphasize greater renewable energy usage. Other proposed policy changes focus on eliminating some of the tax incentives related to drilling activities available to exploration and production companies, which would likely increase the cost of drilling and, in turn, could negatively affect development plans of exploration and production companies and/or increase the cost of energy to consumers. The

company’s management will not be in a position to assess the full impact that the proposed policy changes will have on the energy industry until the policies are adopted.

 

Consolidated Results of Operations (in millions)

 

YEAR ENDED DECEMBER 31, 2009 COMPARED TO YEAR ENDED DECEMBER 31, 2008

 

We reported net income for the year ended December 31, 2009 of $59.1 million, or $1.18 per diluted share. These results compare to net income of $218.9 million, or $4.26 per diluted share, reported for the year ended December 31, 2008. The net income in 2009 included an after tax loss of $81.2 million, or approximately $1.62 per diluted share, on the impairment of goodwill in our rental tools reporting unit. 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 common stock of Boots & Coots International Well Control, Inc. (Boots & Coots).

 

Revenues.  Consolidated revenues decreased $840.2 million, or 28%, in 2009 compared to 2008.

 

Our well site services revenues decreased $173.6 million, or 18%, in 2009 compared to 2008. This decrease was primarily due to reductions in both activity and pricing from the Company’s North American drilling and rental tool operations as a result of the 42% year-over-year decrease in the North American rig count, partially mitigated by revenue growth in our accommodations business.

 

Our accommodations business reported revenues in 2009 that were $54.3 million, or 13%, above 2008. The increase in the accommodations revenue resulted from the expansion of our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada and increased third-party accommodations manufacturing revenues, partially offset by lower accommodations activities in support of conventional oil and natural gas drilling activity in Canada and the weakening of the Canadian dollar versus the U.S. dollar.

 

Our rental tool revenues decreased $121.7 million, or 34%, in 2009 compared to 2008 primarily due to lower rental tool utilization and pricing primarily as a result of significantly reduced completion activity in the U.S. and greater competition.

 

Our drilling services revenues decreased $106.2 million, or 60%, in 2009 compared to 2008 primarily as a result of reduced utilization and pricing in all of our drilling operating regions. Our utilization averaged 36.7% during 2009 compared to 82.4% in 2008.

 

Our offshore products revenues decreased $18.8 million, or 4%, in 2009 compared to 2008. This decrease was primarily due to a decrease in bearing and connectors revenue due to deepwater development project award delays and a decrease in elastomer revenues as a result of reduced drilling and completion activity in North America. These decreases were partially offset by an increase in subsea pipeline revenues.

 

Tubular services revenues decreased $647.8 million, or 44%, in 2009 compared to 2008 as a result of a 46% decrease in tons shipped in 2009, resulting from fewer wells drilled and completed in the period, partially offset by a 2% increase in average selling prices. Although OCTG prices decreased throughout 2009, our average sales price realized increased from 2008 due to sales commitments made in 2008 that extended into 2009.

 

Cost of Sales and Service.  Our consolidated cost of sales decreased $594.8 million, or 27%, in 2009 compared to 2008 primarily as a result of decreased cost of sales at tubular services of $517.1 million, or 41%, and at well site services of $60.6 million, or 11%. Our overall gross margin as a percentage of revenues declined from 24% in 2008 to 22% in 2009 primarily due to lower margins realized in our tubular services, rental tool and drilling services operations during 2009.

 

Our well site services segment gross margin as a percentage of revenues declined from 41% in 2008 to 36% in 2009 despite flat margins in our accommodations business. Our accommodations cost of sales included a $45.8 million increase in third-party accommodations manufacturing and installation costs, which were only partially offset by a reduction in costs stemming from the implementation of cost saving measures in response to the lower conventional oil and natural gas drilling activity levels in Canada and the weakening of the Canadian dollar versus the U.S. dollar. Our rental tool gross margin as a percentage of revenues declined from 42% in 2008 to 28% in 2009 primarily due to significant reductions in drilling and completion activity in both the U.S. and Canada, which negatively impacted pricing and demand for our equipment and services. In addition, a portion of our rental tool costs do not change proportionately with changes in revenue, leading to reduced gross margin percentages. Our

drilling services cost of sales decreased $56.0 million, or 49%, in 2009 compared to 2008 as a result of significantly reduced rig utilization and pricing in each of our drilling operating areas, which led to significant cost reductions. This decline in drilling activity levels also resulted in our drilling services gross margin as a percentage of revenues decreasing from 36% in 2008 to 18% in 2009.

 

Our offshore products segment gross margin as a percentage of revenues was essentially flat (25% in 2008 compared to 26% in 2009).

 

Tubular services segment cost of sales decreased by $517.1 million, or 41%, as a result of lower tonnage shipped partially offset by higher priced OCTG inventory being sold. Our tubular services gross margin as a percentage of revenues decreased from 13% in 2008 to 7% in 2009 due to excess industry-wide OCTG inventory levels in 2009 resulting in lower margins.

 

Selling, General and Administrative Expenses.  SG&A expense decreased $3.8 million, or 3%, in 2009 compared to 2008 due primarily to decreases in accrued incentive bonuses. In addition, our costs have decreased as a result of the implementation of cost saving measures, including headcount reductions and reductions in overhead costs such as travel and entertainment, professional fees and office expenses, in response to industry conditions. SG&A was 6.6% of revenues in 2009 compared to 4.9% of revenues in 2008 due to the significant decline in our revenues during 2009.

 

Depreciation and Amortization.  Depreciation and amortization expense increased $15.5 million, or 15%, in 2009 compared to 2008 due primarily to capital expenditures made during the previous twelve months.

 

Impairment of Goodwill.  We recorded a pre-tax goodwill impairment in the amount of $94.5 million in 2009. The impairment was the result of our assessment of several factors affecting our rental tools reporting unit. We recorded a pre-tax goodwill impairment in the amount of $85.6 million 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 decreased $265.0 million, or 69%, in 2009 compared to 2008 primarily as a result of a decrease in operating income from our rental tool services and tubular operations.

 

Gain on Sale of Investment.  We reported a gain on the sale of investment of $6.2 million in 2008. The sale related to our investment in Boots & Coots common stock. 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 $5.1 million, or 26%, in 2009 compared to 2008 due to reduced debt levels and lower LIBOR interest rates applicable to borrowings under our revolving credit facility. The weighted average interest rate on the Company’s revolving credit facility was 1.5% in 2009 compared to 3.9% in 2008. Interest income decreased as a result of the repayment in 2009 of a note receivable due from Boots & Coots and reduced cash balances in interest bearing accounts. 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 $2.6 million, or 64%, lower in 2009 than in 2008 primarily due to the sale, in August of 2008, of our remaining investment in Boots & Coots.

 

Income Tax Expense.  Our income tax provision for the year ended December 31, 2009 totaled $46.1 million, or 43.6% of pretax income, compared to $154.2 million, or 41.3% of pretax income, for the year ended December 31, 2008. The higher effective tax rate in both years was primarily due to the impairment of goodwill, the majority of which was not deductible for tax purposes. Absent the goodwill impairment in 2009, our effective tax rate was favorably influenced by lower statutory rates applicable to our foreign sourced income.

 

YEAR ENDED DECEMBER 31, 2008 COMPARED TO YEAR ENDED DECEMBER 31, 2007

 

We reported net income attributable to Oil States International, Inc. for the year ended December 31, 2008 of $218.9 million, or $4.26 per diluted share, as compared to $199.8 million, or $3.92 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 services 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 percentage of revenues was relatively constant at 24% in 2008 compared to 23% in 2007.

 

Our well site services segment gross margin as a percentage of revenues declined from 43% in 2007 to 41% in 2008. Our accommodations gross margin as a percentage 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 percentage 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 percentage 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 percentage of revenues of 25% in 2008 and 24% in 2007.

 

Tubular services segment cost of sales increased by $480.5 million, or 61%, 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 SG&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 $0.1 million 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 $154.2 million, or 41.3% of pretax income, compared to $94.9 million, or 32.2% 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. Our effective tax rate in 2008 would have been lower absent the goodwill impairment.

 

Liquidity and Capital Resources

 

The 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.

 

Our primary liquidity needs are to fund capital expenditures, which 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 $453.4 million was provided by operations during the year ended December 31, 2009 compared to cash totaling $257.5 million provided by operations during the year ended December 31, 2008. During 2009, $176.0 million was provided from net working capital reductions, primarily due to a reduction in accounts receivable and lower inventory levels, especially in our tubular services segment. In contrast, during 2008, $171.5 million was used to fund working capital, primarily for OCTG inventory increases and increases in accounts receivable in our tubular services segment due to higher volumes sold and prices paid.

Cash was used in investing activities during the years ended December 31, 2009 and 2008 in the amount of $102.6 million and $246.1 million, respectively. Capital expenditures totaled $124.5 million and $247.4 million during the years ended December 31, 2009 and 2008, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment, and in particular for accommodations investments made in support of Canadian oil sands development. In 2009, we received $21.2 million from Boots & Coots in full satisfaction of our note receivable. Net proceeds from the sale of Boots & Coots common stock totaled $27.4 million during the year ended December 31, 2008. 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. There were no significant acquisitions made by the Company during the year ended December 31, 2009.

 

We currently expect to spend a total of approximately $232 million for capital expenditures during 2010 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 and borrowings under our revolving credit facility. The foregoing capital expenditure budget does not include any funds for opportunistic acquisitions, 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 natural gas, we may 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.

 

Net cash of $296.8 million was used in financing activities during the year ended December 31, 2009, primarily as a result of free cash flow being used to pay off all amounts outstanding under our revolving credit facility. 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 substantially offset by other financing activities.

 

We believe that cash flow from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. 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 and uncertain. 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. Capital availability will be affected by prevailing conditions in our industry, the economy, the financial markets and other 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.

 

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. As of December 31, 2009, the program expired. Through December 31, 2009, a total of $90.1 million of our stock (3,162,294 shares), has been repurchased under this program. 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. Any future share repurchase programs will need to be first authorized by the Board of Directors.

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 the 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 3.0 to 1.0. 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, 2009, we were in compliance with our debt covenants and expect to continue to be in compliance during 2010. 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 2009, our applicable margin over LIBOR was 0.5%. Our weighted average interest rate paid under the Credit Agreement was 1.5% during the year ended December 31, 2009 and 3.9% for the year ended December 31, 2008.

 

As of December 31, 2009, we had no borrowings outstanding under the Credit Agreement, but had $20.3 million of outstanding letters of credit, leaving $479.7 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. that provide for an aggregate borrowing capacity of $5.0 million. As of December 31, 2009, we had no borrowings outstanding under these other facilities. Our total debt represented 10.6% of our total debt and shareholder’s equity at December 31, 2009 compared to 26.9% at December 31, 2008.

 

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 a portion of 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, 2009, we have classified the $175.0 million principal amount of our 23/8% Contingent Convertible Senior Notes (23/8% Notes), net of unamortized discount, 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 notes for conversion during the quarter following the December 31, 2009 measurement date. For a description of these thresholds, please see Note 8 to the Consolidated Financial Statements

included in this Annual Report on Form 10-K. 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.

 

In May 2008, the FASB issued a new accounting standard on the accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement), which changed the accounting for our 23/8% Notes. Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is 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. This accounting standard became effective for the Company beginning January 1, 2009, and is applied retrospectively to all periods presented. See Note 16 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

 

Contractual Cash Obligations.  The following summarizes our contractual obligations at December 31, 2009 (in thousands):

 

 

 

 

Our debt obligations at December 31, 2009 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, 2009.

 

Off-Balance Sheet Arrangements

 

As of December 31, 2009, 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, 2009, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill, foreign tax credit carryforwards and $10 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 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, 2009 totaled $46.1 million, or 43.6% of pretax income, compared to $154.2 million, or 41.3% of pretax income, for the year ended December 31, 2008. The higher effective tax rate in both years was primarily due to the impairment of goodwill, the majority of which was not deductible for tax purposes. Absent the goodwill impairment in 2009, our effective tax rate in 2009 was favorably influenced by lower statutory rates applicable to our foreign sourced income.

 

There are a number of legislative proposals to change the United States tax laws related to multinational corporations. These proposals are in various stages of discussion. It is not possible at this time to predict how these proposals would impact our business or whether they could result in increased tax costs.

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 totaled $218.7 million, or 11.3%, of our total assets, as of December 31, 2009. The assessment of impairment on long-lived assets, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a 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 a 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.

 

We review each reporting unit, as defined in current accounting standards regarding goodwill and other intangible assets to assess goodwill for potential impairment. Our reporting units include accommodations, rental tools, drilling, offshore products and tubular services. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full write-off of goodwill at those reporting units as of December 31, 2008. 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 (a Level 3 fair value measurement). 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 utilize, 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 natural gas 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 to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any. At the date of our annual goodwill impairment test, the IFV’s of our offshore products, accommodations and rental tools reporting units exceeded their carrying values by 120%, 93% and 14%, respectively.

 

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 the accounting standards regarding share-based payments, 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 current accounting standards regarding the 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 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 a new accounting standard on fair value measurements which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. This accounting standard does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. It is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued an accounting standards update deferring the effective date of the fair value accounting standard 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 was permitted, provided the company had not yet issued financial statements, including for interim periods, for that fiscal year. We adopted those provisions of this accounting standard that were unaffected by the delay in the first quarter of 2008. In the first quarter of 2009, we adopted the remaining provisions of this accounting standard. Certain assets are measured at fair value on a nonrecurring basis; that is, they are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment). Such adoption did not have a material effect on our consolidated statements of financial position, results of operations or cash flows.

 

In September 2009, the FASB issued an accounting standards update effective for this and future reporting periods on measuring the fair value of liabilities. Implementation is not expected to have a material impact on the Company’s financial condition, results of operation or disclosures contained in our notes to the consolidated financial statements.

 

In December 2007, the FASB issued a new accounting standard on business combinations. The new accounting standard 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 accounting standard also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. The accounting standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and interim periods within those fiscal years. The accounting standard was effective beginning January 1, 2009; accordingly, any business combinations we engage in after this date will be recorded and disclosed in accordance with this accounting standard. No business combination transactions occurred during the year ended December 31, 2009.

 

In December 2007, the FASB also issued a new accounting standard on noncontrolling interests in consolidated financial statements. This accounting standard requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. It 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. This accounting standard 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. The new accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008. This accounting standard applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. Effective January 1, 2009, we have presented our noncontrolling interests in accordance with this standard.

 

In May 2008, the FASB issued a new accounting standard on the accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement), which changed the accounting for our 23/8% Notes. Under the new rules, for convertible debt instruments that can be settled entirely or partially in cash upon conversion, an entity is 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 difference between bond cash proceeds and the estimated fair value is recorded as a debt discount and accreted to interest expense over the expected life of the bond. Although this accounting standard has no impact on the Company’s actual past or future cash flows, it requires the Company to record a material increase in non-cash interest expense as the debt discount is amortized. The accounting standard became effective for the Company beginning January 1, 2009 and is applied

retrospectively to all periods presented. See Note 16 to the Consolidated Financial Statements in this Annual Report on Form 10-K.

 

In May 2009, the FASB issued a new accounting standard on subsequent events, which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Under the new accounting standard, as under current practice, an entity must record the effects of subsequent events that provide evidence about conditions that existed at the balance sheet date and must disclose but not record the effects of subsequent events which provide evidence about conditions that did not exist at the balance sheet date. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, ending after June 15, 2009. The adoption of this accounting standard did not have a material impact on the Company’s financial condition, results of operation or disclosures contained in our notes to the consolidated financial statements.

 

In June 2009, the FASB issued a new accounting standard, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” This new accounting standard established the “FASB Accounting Standards Codification,” or FASB ASC, as the source of authoritative GAAP recognized by the FASB for non-governmental entities. All existing accounting standards have been superseded and accounting literature not included in the FASB ASC is considered non-authoritative. Subsequent issuances of new standards will be in the form of Accounting Standards Updates, or ASU, that will be included in the ASC. Generally, the FASB ASC is not expected to change GAAP. Pursuant to the adoption of this new accounting standard, we have adjusted references to authoritative accounting literature in our financial statements. Adoption of this standard had no effect on our financial condition, results of operations or cash flows.

 

In October 2009, the FASB issued an accounting standards update that modified the accounting and disclosures for revenue recognition in a multiple-element arrangement. These amendments, effective for fiscal years beginning on or after June 15, 2010 (early adoption is permitted), modify the criteria for recognizing revenue in multiple- element arrangements and the scope of what constitutes a non-software deliverable. The Company did not early adopt this standard and is currently assessing the impact these amendments may have on its financial condition and results of operations.

 

In December 2009, the FASB issued an accounting standards update which amends previously issued accounting guidance for the consolidation of variable interest entities (VIE’s). These amendments require a qualitative approach to identifying a controlling financial interest in a VIE, and requires ongoing assessment of whether an entity is a VIE and whether an interest in a VIE makes the holder the primary beneficiary of the VIE. These amendments are effective for annual reporting periods beginning after November 15, 2009. We do not expect the adoption of these amendments to have a material impact on our financial condition, results of operations or cash flows.

 

In January 2010, the FASB issued an accounting standards update which requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. These amendments are effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. We do not expect the adoption of these amendments to have a material impact on our financial condition, results of operations or cash flows.

 

See also Note 10 — Income Taxes for a discussion of the FASB’s Interpretation No. 48 — Accounting for Uncertainty in Income Taxes.

 

 

Interest Rate Risk.  We have revolving lines of credit that are subject to the risk of higher interest charges associated with increases in interest rates. As of December 31, 2009, we had no floating rate obligations drawn under our revolving credit facilities.

 

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 (i) denominated in currencies other than the U.S. dollar, which is our functional currency, or (ii) 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 2009, our realized foreign exchange losses were $0.3 million and are included in other operating expense (income) in the consolidated statements of income.

 

 

Our consolidated financial statements and supplementary data of the Company appear on pages 57 through 86 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 17 to our Consolidated Financial Statements, which is incorporated herein by reference.

 

 

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.

 

 

 

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 (the Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. 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, 2009 at the reasonable assurance level.

 

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.

 

 

 

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.

 

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009 was conducted. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Intergrated Framework. Based on our assessment we believe that, as of December 31, 2009, the Company’s internal control over financial reporting is effective based on those criteria.

 

 

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 59 and 60 and is incorporated herein by reference.

 

 

During the Company’s fourth fiscal quarter ended December 31, 2009, 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.

 

 

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2009 that was not reported on a Form 8-K during such time.

 

 

(1) Information concerning directors, including the Company’s audit committee financial expert, appears in the Company’s Definitive Proxy Statement for the 2010 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 2010 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 2010 Annual Meeting of Stockholders, under “Section 16(a) Beneficial Ownership Reporting Compliance.” This portion of the Definitive Proxy Statement is incorporated herein by reference.

 

 

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 2010 Annual Meeting of Stockholders.

 

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 2010 Annual Meeting of Stockholders.

 

 

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 2010 Annual Meeting of Stockholders.

 

 

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 2010 Annual Meeting of Stockholders under the heading “Fees Paid to Ernst & Young LLP” and is incorporated herein by reference.

 

 

 

(1) Financial Statements: Reference is made to the index set forth on page 57 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.