Oil States International (OIS) 10-K 2011 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to                

Commission file no. 001-16337

Oil States International, Inc.

(Exact name of registrant as specified in its charter)

Delaware	76-0476605
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

Three Allen Center, 333 Clay Street, Suite 4620, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code:

(713) 652-0582

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Exchange on Which Registered
Common Stock, par value $.01 per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  þ    NO  ¨

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

Large accelerated filer  þ	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company   ¨
	(Do not check if a smaller reporting company)

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

The aggregate market value of common stock held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2011, was $3,864,462,988.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding as of February 14, 2012 was 51,341,686 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for the 2012 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

		Page
PART I
Cautionary Statement Regarding Forward-Looking Statements			2
Item 1.	Business		3 –20
Item 1A.	Risk Factors		20 – 33
Item 1B.	Unresolved Staff Comments		33
Item 2.	Properties		34 – 35
Item 3.	Legal Proceedings		35
Item 4.	Mine Safety Disclosures		35
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36 – 37
Item 6.	Selected Financial Data		38 – 40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40 – 55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		55
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		56
Item 9A.	Controls and Procedures		56 – 57
Item 9B.	Other Information		57
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		57
Item 11.	Executive Compensation		57
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		57
Item 13.	Certain Relationships and Related Transactions, and Director Independence		57
Item 14.	Principal Accountant Fees and Services		57
PART IV
Item 15.	Exhibits, Financial Statement Schedules		58 – 62
SIGNATURES			63
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			64

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PART I

This Annual Report on Form 10-K contains “certain forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933(the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). 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,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” 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. Known material factors that could cause our actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our company are those described below and in Part I, Item 1A, “Risk Factors.”

• the level of demand for and supply of oil and natural gas;

• fluctuations in the current and future prices of oil and natural gas;

• the level of activity and developments in the Canadian oil sands;

• the level of drilling and completion activity;

• the level of mining activity in Australia and demand for coal from Australian exports;

• the level of offshore oil and natural gas developmental activities;

• general economic conditions and continued recovery from the recent recession;

• our ability to find and retain skilled personnel;

• the availability and cost of capital; and

• the other factors identified under the caption “Risks Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

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Item 1.    Business

Our Company

Oil States International, Inc. (the Company or Oil States), through its subsidiaries, is a leading provider of specialty products and services to natural resources companies throughout the world. We operate in a substantial number of the world’s active oil and natural gas and coal producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and Central Asia. Our customers include many national oil companies, major and independent oil and natural gas companies, onshore and offshore drilling companies, other oilfield service companies and mining companies. We operate in four principal business segments — accommodations, offshore products, well site services and tubular services —  and have established a leadership position in certain of our product or service offerings in each segment. 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.

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 (the Commission). The filings are also available through the Commission at the Commission’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, its code of business conduct and ethics and its financial code of 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. The financial code of ethics applies to our principal executive officer, principal financial officer, principal accounting officer and other senior officers. 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 Business Strategy

We have in past years grown our business lines both organically through capital spending 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, in the natural resources market in Australia and in the expansion of our capabilities to manufacture and assemble deepwater capital equipment on a global basis. As part of our long-term growth strategy, 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 Part II, 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 approximately $1.7 billion and has included both growth and maintenance capital expenditures in each of our businesses as follows: accommodations — $927 million, rental tools and services — $349 million, drilling services — $219 million, offshore products — $127 million, tubular services — $25 million and corporate — $4 million.

Since our initial public offering in February 2001, we have completed 40 acquisitions for total consideration of $1.2 billion. Acquisitions of other oilfield service businesses and, most recently, in the accommodations business have been an important aspect of our growth strategy and plan to increase shareholder value. Our

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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 our accommodations, offshore products, well site services and tubular services business lines.

On November 1, 2011, we purchased an open camp accommodations facility located in Carrizo Springs, Texas for total consideration of $2.2 million. This facility will provide accommodations support to customers working in the Eagle Ford Shale basin. The operations of the Carrizo Springs facility have been included in our accommodations segment since its date of acquisition.

On December 30, 2010, we acquired all of the ordinary shares of The MAC Services Group Limited (The MAC), through a Scheme of Arrangement (the Scheme) under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the Australian natural resources market. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. The total purchase price was $638 million, net of cash acquired plus debt assumed of $87 million. The MAC’s operations have been included in our accommodations segment beginning in 2011.

On December 20, 2010, we also acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million and estimated contingent consideration of $3.6 million. Headquartered in Vernal, Utah, with operations in the Rockies and the Bakken Shale region, Mountain West provides remote site workforce accommodations to the oil and gas industry. Mountain West has been included in our accommodations segment since its date of acquisition.

The Company funded the acquisitions of The MAC and Mountain West with cash on hand and draws under our senior secured credit facilities. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.

On October 5, 2010, we purchased all of the equity of Acute Technological Services, Inc. (Acute) for total consideration of $30.2 million. Headquartered in Houston, Texas with additional operations in Brazil, Acute provides metallurgical and welding engineering, consulting and services to the oil and gas industry in support of critical, complex subsea component manufacturing and deepwater riser fabrication on a global basis. Acute has been included in our offshore products segment since its date of acquisition. We funded the Acute acquisition using cash on hand and our then existing credit facility.

Our Industry

We operate principally in the oilfield services industry and provide a broad range of products and services to our customers through our accommodations, offshore products, well site services and tubular services business segments. In our accommodations segment, we also support the mining industry in Australia. See Note 14 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements” for financial information by segment and a geographical breakout of revenues and long-lived assets. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to spend capital on the exploration for and development of oil, natural gas, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our products and services is highly sensitive to current and expected commodity prices.

Our historical 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. Due to the acquisition of The MAC, beginning in 2011, our results are also influenced by the level of activity in the natural resource market in Australia. For additional information about activities in each of our segments, please see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our accommodations business is significantly influenced by the level of development of oil sands deposits in Alberta, Canada, activity levels in support of oil and gas development in Canada and the United States and in natural resource markets, primarily in Australia. Despite the general economic downturn in 2009 and early 2010 as a result of the global financial crisis, activity in our accommodations business has grown significantly in the last six years.

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New order activity for deepwater capital equipment was limited beginning in the fourth quarter of 2008 and continued to decline throughout 2009 due to project postponements, cancellations and deferrals by customers as a result of the general economic downturn, reduced oil prices and the Macondo well incident in the U.S. Gulf of Mexico. This reduction in order activity led to declines in our offshore products backlog and decreased revenues and profits in 2010. With the improvement in oil prices over the last two years along with the improved outlook for long-term oil demand, we began experiencing increased bidding and quoting activity for our offshore products in the latter part of 2010 that continued throughout 2011, although such activity levels were negatively affected by the Macondo well incident in the U.S. Gulf of Mexico and resultant regulatory delays and subsequent rulemaking. As a result of this increased activity, backlog in our offshore products segment increased from $354 million as of December 31, 2010 to a record $535 million as of December 31, 2011. We anticipate global deepwater spending to continue including new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico, South East Asia and Australia over the next twelve months.

Our well site services businesses are significantly influenced by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world. Activity levels materially declined throughout 2009 in most of our well site services businesses. Activity levels in 2010 and 2011 improved significantly off their 2009 troughs. Until recently, overall industry activity has been primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, with higher oil prices, lower natural gas prices and the advancement of horizontal drilling and completion techniques, activity in North America has shifted to a greater proportion of oil and liquids-rich drilling. According to rig count data published by Baker Hughes Incorporated, the oil rig count in the U.S. now totals approximately 1,200 rigs, the highest oil-related rig count in over 20 years, comprising approximately 62% of total U.S. drilling activity.

Our tubular services business is influenced by the overall level of U.S. drilling activity, the types of wells being drilled, movements in global steel and steel input prices and the overall industry level of oil country tubular goods (OCTG) inventory and pricing. Our tubular services business has historically been our most cyclical business segment. Declining OCTG prices in 2009 coupled with weaker demand for OCTG, caused by a decline in U.S. drilling, led to significantly lower revenues and margins for our tubular services business in 2009. The recovery in U.S. drilling activity beginning in 2010 and continuing throughout 2011 led to increased tubular services volumes and revenues. Price increases announced by the major U.S. mills during 2011 resulted in increased margins for our tubular services business in 2011.

Accommodations

Overview

During the year ended December 31, 2011, we generated approximately 25% of our revenue and 45% of our operating income, before corporate charges, from our accommodations segment. We are one of North America’s and, as a result of our acquisition of The MAC in December 2010, Australia’s largest integrated providers of accommodations services for people working in remote locations. Our scalable modular facilities provide temporary and permanent work force accommodations where traditional infrastructure is not accessible or cost effective. Once facilities are deployed in the field, we also provide catering and food services, housekeeping, laundry, facility management, water and wastewater treatment, power generation, communications and redeployment logistics. Our accommodations are employed to support work forces in the Canadian oil sands and in a variety of oil and natural gas drilling, mining and related natural resource applications as well as forest fire fighting and disaster relief efforts, primarily in Canada, Australia and the United States.

Accommodations Market

Our accommodations business has grown significantly in recent years in large part 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 great extent by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year time frame to complete oil sands projects and the costs associated with development of such large scale projects. Utilization of our existing Canadian accommodations capacity and our future expansions will largely depend on continued oil sands development spending.

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Beginning in 2011, as a result of our acquisition of The MAC, our accommodations business entered into the Australian natural resources market. The Australian natural resources sector plays a vital role in the Australian economy. The growth of Australian natural resource commodity exports over the last decade has been largely driven by strong Asian demand for iron ore, coal and liquefied natural gas (LNG). The Australian natural resources sector is Australia’s largest contributor to exports, a major contributor to gross domestic product, a major employer and a major contributor to government revenue. The current activities of our Australian accommodations business are primarily related to supplying accommodations in support of metallurgical coal mining in the Bowen Basin region of Queensland.

Volumes and prices of commodities have historically varied significantly and are difficult to predict. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. Strong economic growth in emerging economies, such as China and India, with associated strong demand for mineral and natural resources such as coal, iron ore and LNG, has more than offset more moderate growth in the developed economies including the United States, Japan and Europe. This demand is expected to underpin continued investment and growth in the Australian natural resources market.

Products and Services

Since mid-year 2006, we have installed over 9,900 rooms in our lodge properties supporting oil sands activities in northern Alberta. Our growth plan for this part of our business includes the expansion of these properties where we believe there is durable long-term demand. During 2011, we added 2,485 rooms (net of retirements) to its major oil sands lodges by expanding its Wapasu Creek and Athabasca Lodges and constructing the new Henday Lodge. We are currently expanding the capacity of our Beaver River Executive Lodge, Athabasca Lodge and Henday Lodge. These expansions will add approximately 500 rooms by the end of the first half of 2012.

Our Australian accommodations business operates eight villages with over 7,300 rooms and has a significant development portfolio in Australia. The MAC provides accommodation services to mining and related service companies (including construction contractors) under medium-term contracts (three to five years). Our Australian accommodations villages are strategically located in proximity to long-life, low-cost mines operated by large mining companies. During 2011, the Company added 2,103 rooms (net of retirements) to its Australian accommodations business by expanding existing villages and by constructing two new villages. We are currently expanding the capacity of several of our Australian villages and constructing a new village in Karratha, Western Australia.

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Total rentable rooms for our major Canadian oil sands lodges and Australian villages were as follows:

	As of December 31,
	2011		2010
Canadian Oil Sands Lodges
Wapasu		5,174		4,013
Athabasca		1,776		1,537
Henday		1,120		—
Beaver River		732		732
Conklin		584		608
Lakeside		510		510
Christina Lake		72		83
Total Canadian Oil Sands Lodges		9,968		7,483
Australian Villages
Coppabella		2,556		1,654
Dysart		1,491		1,249
Moranbah		1,180		889
Middlemount		816		690
Nebo		490		490
Calliope		300		—
Narrabri		242		—
Kambalda		238		238
Total Australian Villages		7,313		5,210

In addition to our large-scale lodge and village 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, two manufacturing locations in Ormeau and Yatala, Queensland, Australia, one in Belle Chasse, Louisiana and, since December 2011, one in Johnstown, Colorado, which specialize in the design, engineering, production, transportation and installation of a variety of portable modular buildings, predominately for our own use. We manufacture accommodations facilities to suit the climate, terrain and population of a specific project site.

To a significant extent, the Company’s recent capital expenditures have focused on opportunities in the oil sands region in northern Alberta and, beginning in 2011, in our Australian accommodations business. Since the beginning of 2005, we have spent $816.8 million, or 54.7%, of our total consolidated capital expenditures in our Canadian and Australian accommodations business. Most of the capital investments in Canada have been in support of oil sands developments, both for initial construction phases and ongoing operations. Oil sands related accommodations revenues have increased from 33% of total accommodations revenues in 2005 to 55% in 2011.

Regions of Operations

Our accommodations business is focused primarily in northern Canada and Queensland, Australia, but also operates in Western Australia, New South Wales, the U.S. Rocky Mountain corridor and the Bakken Shale region (Montana, North Dakota and Saskatchewan, Canada), the Fayetteville Shale region of Arkansas, the Eagle Ford Shale region of Texas 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.

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Customers and Competitors

Our customers operate in a diverse mix of industries including primarily oil sands mining and development; drilling, exploration and extraction of oil and natural gas and coal and other extractive industries. To a lesser extent, we also support other activities, including pipeline construction, forestry, humanitarian aid and disaster relief, and support for military operations. Our largest customers in 2011 were Imperial Oil and Suncor Energy Oil Sands LP in Canada and BHP Billiton Mitsubishi Alliance and Vale S.A. in Australia. Our primary competitors in North America include Aramark Corporation, Compass Group PLC, ATCO Structures and Logistics Ltd., Black Diamond Group Limited, Horizon North Logistics, Inc., Clean Harbors, Inc. and Target Logistics Management, LLC. Our primary competitors in Australia include Auzcorp Pty Ltd, ISS Facility Services, Inc., Sodexo Inc., Ausco Modular Pty Limited and Fleetwood Corporation Limited. Accommodations are also sometimes owned and/or operated by our existing and potential customers.

Offshore Products

Overview

During the year ended December 31, 2011, we generated approximately 17% of our revenue and 17% of our operating income, before corporate charges, from our offshore products segment. Through this segment, we design and manufacture a number of cost-effective, technologically advanced products for the offshore energy industry. In addition, we 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, deepwater mooring systems, cranes, offshore equipment, installation services and subsea pipeline products and blow-out preventer stack integration and repair services. We have facilities in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil; England; Singapore, Thailand, Vietnam and India 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. To a lesser extent, 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, tension leg platforms, floating production, storage and offloading (FPSO) vessels, and on other marine vessels, floating rigs, vessels and jack-up rigs. Our products and services include:

• flexible bearings and connector products;

• subsea pipeline products;

• marine winches, mooring systems, cranes and rig equipment;

• conductor casing connections and pipe;

• drilling riser and related repair services;

• blowout preventer stack assembly, integration, testing and repair services; and

• other products and services.

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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:

• pipeline end manifolds, pipeline end terminals;

• midline tie-in sleds;

• forged steel Y-shaped connectors for joining two pipelines into one;

• pressure-balanced safety joints for protecting pipelines and related equipment from anchor snags or a shifting sea-bottom;

• electrical isolation joints; and

• hot tap clamps that allow new pipelines to be joined into existing lines without interrupting the flow of petroleum product.

We provide diverless connection systems for subsea flowlines and pipelines. Our HydroTech^® collet connectors provide a high-integrity, proprietary metal-to-metal sealing system for the final hook-up of deep offshore pipelines and production systems. They also are used in diverless pipeline repair systems and in future pipeline tie-in systems. Our lateral tie-in sled, which is installed with the original pipeline, allows a subsea tie-in to be made quickly and efficiently using proven HydroTech^® connectors without costly offshore equipment mobilization and without shutting off product flow.

We provide pipeline repair hardware, including deepwater applications beyond the depth of diver intervention. Our products include:

• repair clamps used to seal leaks and restore the structural integrity of a pipeline;

• mechanical connectors used in repairing subsea pipelines without having to weld;

• misalignment and swivel ring flanges; and

• pipe recovery tools for recovering dropped or damaged pipelines.

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Marine Winches, Mooring Systems, Cranes and Rig Equipment.    We design, engineer and manufacture marine winches, mooring systems, cranes and certain 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 preventer 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.

To a lesser extent, our offshore products segment also produces a variety of products for use in applications other than in the offshore oil and gas industry. For example, we provide:

• elastomer consumable downhole products for onshore drilling and production;

• sound and vibration isolation equipment for the U.S. Navy submarine fleet;

• metal-elastomeric FlexJoints^® used in a variety of naval and marine applications; and

• drum-clutches and brakes for heavy-duty power transmission in the mining, paper, logging and marine industries.

Backlog.    Backlog in our offshore products segment was $535 million at December 31, 2011, compared to $354 million at December 31, 2010 and $206 million at December 31, 2009. We expect in excess of 85% of our backlog at December 31, 2011 to be recognized as revenue during 2012. 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, Southeast Asia, India and Australia.

Customers and Competitors

We market our products and services to a broad customer base, including direct end users, engineering and design companies, prime contractors, and at times, our competitors through outsourcing arrangements. Our largest customers in 2011 were Halliburton Company, Transocean Ltd., and Chevron Corporation. Our main competitors include Techlam, Cameron International Corporation, Sea Trax, Inc., GE Oil & Gas, and National Oilwell Varco, Inc.

Well Site Services

Overview

During the year ended December 31, 2011, we generated approximately 19% of our revenue and 26% of our operating income, before corporate charges, from our well site services segment. Our well site services segment includes a broad range of products and services that are used to drill for, establish and maintain the flow of oil

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and natural gas from a well throughout its lifecycle. In this segment, our operations include completion-focused equipment and services as well as land drilling services. We use our fleet of drilling rigs and rental equipment to serve our customers at well sites and project development locations. Our products and services are used primarily in onshore applications throughout the exploration, development and production phases of a well’s life.

Well Site Services Market

Demand for our drilling rigs and rental equipment 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.

Products and Services

Rental Equipment.    Our rental equipment business provides a wide range of products and services for use in the onshore and offshore oil and gas industry, including:

• wireline and coiled tubing pressure control equipment;

• wellhead isolation equipment;

• pipe recovery systems;

• thru-tubing fishing services;

• hydraulic chokes and manifolds;

• blow out preventers;

• well testing and flowback equipment, including separators and line heaters;

• gravel pack operations on well bores; and

• surface control equipment and down-hole tools utilized by coiled tubing operators.

Our rental equipment is primarily used during the completion and production stages of a well. As of December 31, 2011, we provided rental equipment at 56 distribution points throughout the United States, Canada, Mexico and Argentina, compared to 58 distribution points at December 31, 2010. We continue to consolidate operations in areas where our product lines previously had separate facilities and close facilities in areas where operations are marginal in order to streamline operations, enhance our facilities and improve marketing efficiency. We provide rental equipment on a daily rental basis with rates varying depending on the type of equipment and the length of time rented. Generally, this equipment is operated or installed by our field technicians 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. Our largest customers in 2011 were Anadarko Petroleum Corporation and Chesapeake Energy. Competition in the rental tools and services business is widespread and includes many smaller companies, although we also compete with the larger oilfield service companies for certain products and services. The growth in the oil and gas industry in 2011 increased demand for our rental tools equipment and services, which resulted in both higher revenues and margins when compared to 2010.

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. We serve two primary markets with our drilling services business: the Permian Basin in West Texas and the Rocky Mountain region. Drilling services are typically used during the exploration and development stages of a field. As of December 31, 2011, after taking two of our smaller rigs out of commission in 2011, we had a total of 34 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds, 14 of which were fabricated and/or assembled in our Odessa, Texas facility with components purchased from specialty vendors. Twenty-five of these drilling rigs are based in Odessa, Texas and nine are based in the Rocky Mountains region. Utilization of our drilling rigs increased from an average of 72% in 2010 to an average of 82%

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in 2011. On December 31, 2011, 32 of our rigs were working or under contract with utilization of approximately 94%. Subsequent to December 31, 2011, we lost one of our drilling rigs located in the Rocky Mountain region as a result of a constructive total loss due to a fire.

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. Under a footage 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 see changes in pricing, utilization and contract terms. Our largest customers in 2011 were Energen Resources Corporation, Apache Corporation and SandRidge Energy, Inc. The land drilling business is highly fragmented, and our competition consists of a small number of larger companies and many smaller companies. Our Permian Basin drilling activities target primarily oil reservoirs while our Rocky Mountain drilling activities target oil, liquids-rich and natural gas reservoirs.

Tubular Services

Overview

During the year ended December 31, 2011, we generated approximately 40% of our revenue and 12% of our operating income, before corporate charges, from our tubular services segment. Through 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:

• distribute a broad range of casing and tubing; and

• provide threading, logistical and inventory management services.

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 2011, we purchased 58% of our total tubular goods from a single domestic supplier and 85% of our total OCTG purchases were from three 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 collapse 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 and can put downward pressure on OCTG pricing. 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 deeper wells and 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

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mills. We do not manufacture any of the tubular goods that we distribute and, 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 ten offices and facilities located near areas of oil and natural gas exploration and development activity.

In our tubular services segment, inventory management is critical to our success. We maintain on-the-ground inventory in five company-owned yards and approximately 90 third-party 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 an inventory management system, designed specifically for the OCTG industry, which enables us to track our product inventory and shipments.

Yard Operations.    Our 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 Crosby yard is on 109 acres, is an ISO 9001-certified facility, and has a rail spur, 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 pipe storage capability and patented pipe cleaning machines. We offer services at our Crosby facility typically outsourced by other distributors, including the following: threading, inspection, cleaning, cutting, logistics, rig returns, installation of float equipment and non-destructive testing. We also offer tubular services at our facilities in Midland and Godley, Texas, Searcy, Arkansas and Montoursville, Pennsylvania. Our Midland, Texas facility, which services the Permian Basin area, covers approximately 69 acres and has more than 600 pipe racks. Our Godley, Texas facility, which services the Barnett shale area, has approximately 360 pipe racks on approximately 31 acres and is serviced by a rail spur. Our Searcy location, which services the Fayetteville shale area, has approximately 140 pipe racks on 14 acres. Our Montoursville, Pennsylvania location, which services the Marcellus shale area, has more than 200 pipe racks on 24 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. Alliance or program arrangements refer to agreements whereby a customer bids the tubular requirements for a number of wells at one time. Although our alliances are generally not as profitable as the spot market and can generally 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, Customers and Competitors

We source the OCTG we sell from domestic and international manufacturers. Our largest supplier is U.S. Steel Group. Although we have a leading market share position in tubular services distribution, the market is highly fragmented. Our largest customers in 2011 were Chesapeake Energy, ConocoPhillips, and Occidental Petroleum Corporation. Our main competitors in tubular distribution are Edgen Group Inc., MRC Global, Inc., Pipeco Services Inc. and Premier Pipe L.P.

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Seasonality of Operations

Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, Australia, 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 our ability to provide services. During the Australian rainy season, generally between the months of November and April, our accommodations operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Severe winter weather conditions in the Rocky Mountain region can restrict access to work areas for our well site services and accommodations segment operations. 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, 2011, the Company had 7,949 full-time employees on a consolidated basis, 44% of whom are in our accommodations segment, 30% of whom are in our well site services segment, 23% of whom are in our offshore products segment, 2% of whom are in our tubular services segment and 1% of whom are in our corporate headquarters. We were party to collective bargaining agreements covering 2,124 employees located in Canada, Australia, the United Kingdom and Argentina as of December 31, 2011. We believe relations with our employees are good.

Government Regulation

Our business is significantly affected by foreign and domestic laws and regulations at the federal, provincial, state and local levels relating to the oil, natural gas and mining industries, mining worker safety and environmental protection. Changes in these laws, including more stringent regulations and increased levels of enforcement of these laws and regulations, could significantly affect our business. We cannot predict changes in the level of enforcement of existing laws and regulations or how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our future operations or earnings. We also are not able to predict whether additional laws and regulations will be adopted.

We depend on the demand for our products and services from oil and natural gas exploration and production companies. This demand is affected by changing taxes, price controls and other laws and regulations relating to the oil and natural 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, provincial, 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

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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.

For example, in Canada, the Federal Government in September 2010 appointed an Oil Sands Advisory Panel to review and comment upon existing scientific studies and literature regarding water monitoring in the Lower Athabasca region and provide recommendations for improving such monitoring. The Oil Sands Advisory Panel presented its final report to the Minister of the Environment in December 2010. In response to this report, Environment Canada, with input from the government of Alberta through Alberta Environment, developed an environmental monitoring plan, the first phase of which was published in March 2011. This monitoring plan, when and if implemented, would establish more comprehensive monitoring programs for water quality, aquatic ecosystems, air quality and terrestrial biodiversity and habitat. The results of such monitoring may lead to increased levels of regulation and cost of government oversight.

Further, in January 2011, the Province of Alberta established a Provincial Environmental Monitoring Panel with a mandate to recommend a world class environmental evaluation, monitoring and reporting system, generally for the Province and specifically for the lower Athabasca Region where oil sands are produced. This panel issued its recommendations to the Alberta Minister of the Environment in July 2011.

If and when new monitoring systems or requirements are implemented, these new requirements may increase costs and lead to increased levels of regulation, enforcement and cost for us and our customers and reduced activity and demand for our services.

Further, the Province of Alberta released a report in December 2010 regarding regulatory changes to be implemented in 2011 regarding Alberta Environment’s regulation of oil sands operations. The report proposed regulatory changes would include increased reclamation security requirements, increased monitoring requirements for water quality, and additional requirements for the management of tailings ponds. So far, the Government of Alberta has revised security requirements for all mines, including oil sands mines. These revised security requirements, as well as the additional contemplated changes, may result in additional costs or liabilities for our customers’ operations.

With regard to our U.S. operations, we generate wastes, including hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. The United States Environmental Protection Agency, or EPA, and comparable state agencies have limited the approved methods of disposal for some types of hazardous wastes and nonhazardous solid 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. For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting reconsideration of the continued application of this RCRA exclusion but, to date, the EPA has not taken any action on the petition. A loss of this exclusion 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 nonhazardous solid wastes.

The federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, 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

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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, as amended, 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 storm water, and we have a system for securing and maintaining these permits. In addition, the Oil Pollution Act of 1990, as amended, or OPA, 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 OPA, 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 and services 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 and disposal of fracturing fluids 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, public disclosure and construction and operational compliance requirements for our oil and gas industry customers more stringent for hydraulic fracturing. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, there have been developments indicating that more federal regulatory involvement may occur. The EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing in the United States under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering adopting legal requirements that could impose more stringent requirements on hydraulic fracturing activities. In the event that new or more stringent federal or state legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our rental tools and services business.

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In addition, certain domestic governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on the results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of oil and natural gas by exploration and production operations, some of which are our customers, and thus reduce demand for our North American completion products and services, tubular services and accommodations services.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling rig leading to an oil spill from the Macondo well operated in the ultra deep water in the U.S. Gulf of Mexico. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in May 2010, the U.S. Department of the Interior, initially through its federal Minerals Management Service, or MMS, and subsequently through the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, when the MMS was renamed the BOEMRE in June 2010, implemented a moratorium on certain deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. While the moratorium was in place, the BOEMRE began issuing a series of “Notices to Lessees and Operators”, or NTLS, imposing additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico, and has delayed the approval of applications to drill in both deepwater and shallow-water areas. Even with the lifting of the moratorium, offshore drilling activity has been delayed by adjustments in operating procedures, compliance certifications, and lead times for permits and inspections, as a result of the changes in the regulatory environment. Moreover, effective October 1, 2011, BOEMRE was split into two federal bureaus, the Bureau of Ocean Energy Management, or BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies, and the Bureau of Safety and Environmental Enforcement, or BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, some of our customers are required to interact with two newly formed federal bureaus to obtain approval of exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested from the former agency and implemented in the two new federal bureaus. In addition to the drilling restrictions and new safety and permitting measures already issued by the BOEMRE, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, including proposals to significantly increase the minimum financial responsibility demonstration required under OPA. Uncertainties and delays caused by the new regulatory environment have and will continue to have an overall negative effect on Gulf of Mexico drilling activity and, to a certain extent, our financial results.

Some of our operations as well as those of our oil and natural gas customers in the U.S. also result in emissions of regulated air pollutants. The federal Clean Air Act, as amended, or CAA, 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. In addition, amendment of the CAA or comparable state laws may cause our oil and natural gas exploration and production customers to incur capital expenditures for installation of air pollution control equipment and to

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encounter construction delays while applying for and receiving new or amended permits, which could have an adverse effect on demand for our products and services. For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production, including, among other things, the application of reduced emission completion techniques, referred to as “green completions,” for completion of newly drilled and fractured wells in addition to establishing specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. Final action on the proposed rules is expected no later than April 3, 2012.

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. Recently, the Government of Canada has announced a number of regulatory changes to address GHG emissions from motor vehicles and coal fired electricity generation. These changes may have implications for our costs of operations.

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 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.

Our Australian accommodations businesss is regulated by general statutory environmental controls at both the state and federal level. These controls include: the regulation of hard and liquid waste, including the requirement for tradewaste and/or wastewater permits or licences; the regulation of water, noise, heat, and

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atmospheric gases emissions; the regulation of the production, transport and storage of dangerous and hazardous materials (including asbestos); and the regulation of pollution and site contamination. Some specified activities, for example, sewage treatment works, may require regulation at a state level by way of environmental protection licenses which also impose monitoring and reporting obligations on the holder. There is an increasing emphasis from state and federal regulators on sustainability in business operations. Federal requirements are now in place for the mandatory disclosure of energy performance under building rating schemes. These schemes require the tracking of specific environmental performance factors. Carbon reporting requirements currently exist for corporations which meet a reporting threshold for greenhouse gases or energy use or production for a reporting (financial) year under national legislation. In addition, the Australian Commonwealth Government’s carbon pricing mechanism (“CPM”) commences on 1 July 2012. Under the CPM, entities that are responsible for facilities that meet specified emissions thresholds will be required to purchase and surrender permits representing their carbon emissions. The CPM is intended to operate as a carbon trading scheme, commencing with a three year fixed price period, followed by a flexible price cap-and-trade emissions trading scheme. Although our Australian accommodations facilities are currently below the emissions thresholds specified by the CPM and are, thus, not affected by the CPM, this could change in the future and the resultant change could have an adverse effect on our Australian operations and financial results.

Although the United States is not participating in the Kyoto Protocol, the U.S. EPA determined in December 2009 that emissions of GHGs present an endangerment to public health and the environment. Based on these findings, the EPA has adopted regulations to restrict emissions of greenhouse gases under existing provisions of the CAA, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that regulates emissions of greenhouse gases from certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including, among others, offshore and onshore oil and natural gas production facilities, on an annual basis.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us or our customers to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas, which could reduce the demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of 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 and Australia, pursuant to the Kyoto Protocol or other international or locally enforceable requirements, could adversely affect demand for our services.

The federal Endangered Species Act, as amended, or the ESA, restricts activities in the United States that may affect endangered or threatened species or their habitats. If endangered species are located in areas of the United States where our oil and natural gas exploration and production customers operate, such operations could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service

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is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas of the United States where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our products and services.

Item 1A.    Risk Factors

The risks described in this Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Our business is subject to a number of economic risks.

Financial markets worldwide experienced extreme disruption in the past four 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. Such economic events can recur 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 and mining 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 and Australian Dollar, could also adversely affect our results.

Decreased customer expenditure levels will adversely affect our results of operations.

Demand for our products and services is sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and gas and mining companies, including national oil companies. If our customers’ expenditures decline, our business will suffer. The oil and gas and mining industries’ willingness to explore, develop and produce depends largely upon the availability of attractive drilling prospects and the prevailing view of future commodity prices. Prices for oil, coal, natural gas, and other minerals are subject to large fluctuations in response to 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 commodity pricing would have material adverse effects on 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 or coal production. Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil, coal and gas. Many factors affect the supply and demand for oil, coal, natural gas and other minerals and, therefore, influence product prices, including:

• the level of drilling activity;

• the level of production;

• the levels of oil and natural gas inventories;

• depletion rates;

• worldwide demand for oil and natural gas;

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• the expected cost of finding, developing and producing new reserves;

• delays in major offshore and onshore oil and natural gas field development timetables;

• the level of activity and developments in the Canadian oil sands;

• the level of demand for coal and other natural resources from Australia;

• the availability of attractive oil and natural gas field prospects, which may be affected by governmental actions or environmental activists which may restrict drilling;

• the availability of transportation infrastructure, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;

• global weather conditions and natural disasters;

• worldwide economic activity including growth in underdeveloped countries, such as China and India;

• national government political requirements, including the ability of the Organization of Petroleum Exporting Companies (OPEC) to set and maintain production levels and prices for oil and government policies which could nationalize or expropriate oil and natural gas exploration, production, refining or transportation assets;

• the level of oil and gas production by non-OPEC countries;

• the impact of armed hostilities involving one or more oil producing nations;

• rapid technological change and the timing and extent of alternative energy sources, including liquefied natural gas (LNG) or other alternative fuels;

• environmental regulation; and

• domestic and foreign tax policies.

Our business may be adversely affected by extended periods of low oil prices or unsuccessful exploration results may decrease deepwater exploration and production activity or oil sands development and production in Canada.

Two of our businesses, where we manufacture offshore products for deepwater exploration and production and where we supply accommodations for oil sands developments, 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, oil sands, Australian mining and LNG investment 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 accommodations segment.

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.

Hydraulic fracturing is an important and commonly used process for the completion of oil and natural gas 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 production. 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, public disclosure and construction and operational compliance requirements more stringent for hydraulic fracturing. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, there have been developments indicating that more federal regulatory involvement may occur. The EPA has asserted federal

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regulatory authority pursuant to the federal Safe Drinking Water Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing in the United States under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering adopting legal requirements that could impose more stringent requirements on hydraulic fracturing activities. In the event that new or more stringent federal or state legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our rental tools and services and tubular services businesses.

In addition, certain domestic governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of oil and natural gas by exploration and production operations, some of which are our customers, and thus reduce demand for our North American completion products and services.

In our accommodations business supporting mining, our clients’ production or price issues may adversely affect us.

The volumes and prices of the products of our clients, including coal and gold, have historically varied significantly and are difficult to predict. The demand for, and price of, these minerals and commodities is highly dependent on a variety of factors, including international supply and demand, the price and availability of alternative fuels, actions taken by governments and global economic and political developments. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. We expect that a material decline in mineral and commodity prices could result in a decrease in the activity of our clients with the possibility that this would materially adversely affect us. No assurance can be given regarding future volumes and/or prices relating to the activities of our clients.

Our customers in the accommodations business are exposed to a number of unique operating risks which could also adversely affect us.

We could be materially adversely affected by disruptions to the operation of our clients caused by any one of or all of the following singularly or in combination:

• domestic and international pricing and demand for the natural resource being produced at a given project (or proposed project);

• unexpected problems and delays during the development, construction and project start-up which may delay the commencement of production;

• unforeseen and adverse climatic, geological, geotechnical, seismic and mining conditions;

• lack of availability of sufficient water or power to maintain their or our operations;

• water or food quality or safety issues;

• lack of availability or failure of the required infrastructure necessary to maintain or to expand their operations;

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• the breakdown or shortage of equipment and labor necessary to maintain their or our operations;

• risks associated with the natural resources industry being subject to various regulatory approvals. Such risks may include a Government Agency failing to grant an approval or failing to renew an existing approval, or the approval or renewal not being provided by the Government Agency in a timely manner or the Government Agency granting or renewing an approval subject to materially onerous conditions;

• risks to land titles, mining titles and use thereof as a result of native title claims;

• claims by persons living in close proximity to mining projects, which may have an impact on the consents granted;

• interruptions to the operations of our clients caused by industrial accidents or disputes; and

• delays in or failure to commission new infrastructure in timeframes so as not to disrupt client operations.

Our accommodations business is exposed to a number of general risks that could materially adversely affect our assets and liabilities, financial position, profits, prospects and share price.

Examples of these broad general risks which may impact our performance include:

• abnormal stoppages in the production or delivery of the products of our clients due to factors such as industrial disruption, infrastructure failure, war, political or civil unrest;

• cost overruns in the provision of new rooms or in other associated or related capital expenditure;

• higher than budgeted costs associated with the provision of accommodations services;

• our clients not renewing their contracts, renewing them on less favorable terms, or other loss of clients;

• our inability to properly treat and dispose of wastewater at our facilities;

• failure of our clients to meet their obligations under their contracts;

• extreme weather conditions adversely affecting our operations or the operations of our clients; and

• a major disaster at one or more of our large accommodations facilities involving fire, communicable diseases, criminal acts or other events causing significant reputational damage.

Development of permanent infrastructure in the Canadian oil sands region, regions of Australia or various U.S. locations where we locate our accommodations assets 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, or regions of Australia where we locate accommodations villages demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

Construction risks exist in our accommodations business.

There are a number of general risks that might impinge on companies involved in the development, construction, manufacture and installation of facilities as a prerequisite to the management of those assets in an operational sense. We might be exposed to these risks from time to time by relying on these corporations and/or other third parties which could include any and/or all of the following;

• the construction activities of our accommodations business are partially dependent on the supply of appropriate construction and development opportunities;

• development approvals, slow decision making by counterparties, complex construction specifications, changes to design briefs, legal issues and other documentation changes may give rise to delays in completion, loss of revenue and cost over-runs. Delays in completion may, in turn, result in termination of accommodation supply contracts;

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• other time delays that may arise in relation to construction and development include supply of labor, scarcity of construction materials, lower than expected productivity levels, inclement weather conditions, land contamination, cultural heritage claims, difficult site access, or industrial relations issues;

• objections aired by community interest, environment and/or neighborhood groups which may cause delays in the granting or approvals and/or the overall progress of a project;

• where we assume design responsibility, there is a risk that design problems or defects may result in rectification and/or costs or liabilities which we cannot readily recover; and

• there is a risk that we may fail to fulfill our statutory and contractual obligations in relation to the quality of our materials and workmanship, including warranties and defect liability obligations.

Our financial results could be adversely impacted by changes in the regulation of offshore oil and natural gas exploration and development activity as a result of the Macondo well incident.

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has issued a series of Notices to Lessees and Operators (NTLs), has imposed additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico, and has delayed the approval of applications to drill in both deepwater and shallow-water areas. Uncertainties and delays caused by the new regulatory environment have and will continue to have an overall negative effect on Gulf of Mexico drilling activity, and to a certain extent, our financial results.

In addition to the drilling restrictions and new safety and permitting measures already issued by the BOEMRE, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, including proposals to significantly increase the minimum financial responsibility demonstration required under the Oil Pollution Act of 1990. Any increased regulation of the exploration and production industry as a whole that arises out of the Macondo well incident could result in fewer companies being financially qualified to operate offshore in the U.S., could result in higher operating costs for our customers and could reduce demand for our services.

We have a significant concentration of our accommodations business located in the oil sands region of Alberta, Canada and in the Bowen Basin of Queensland, Australia.

Because of the concentration of our accommodations business in the Canadian oil sands and in the coal region of Queensland, Australia, two relatively small geographic areas, 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.

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, 2011, goodwill represented approximately 13% of our total assets. We have recorded goodwill because we paid more for some of our businesses that we acquired 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

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during the global financial crisis, 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. Similarly, 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 and services reporting unit. It is possible that we could recognize additional goodwill impairment losses in the future if, among other factors:

• global economic conditions deteriorate;

• the outlook for future profits and cash flow for any of our reporting units deteriorate as the result of many possible factors, including, but not limited to, increased or unanticipated competition, technology becoming obsolete, further reductions in customer capital spending plans, loss of key personnel, adverse legal or regulatory judgment(s), future operating losses at a reporting unit, downward forecast revisions, or restructuring plans;

• costs of equity or debt capital increase further; or

• valuations for comparable public companies or comparable acquisition valuations deteriorate further.

The level and pricing of tubular goods imported into the United States could decrease demand for our tubular goods inventory and adversely impact our results of operations. Also, if steel mills were to sell a substantial amount of goods directly to end users in the United States, our results of operations could be adversely impacted.

Although imports of OCTG from China are currently restricted by trade sanctions imposed by the U.S. government, lower-priced tubular goods from a number of foreign countries are still imported into the U.S. tubular goods market. If the level of imported lower-priced tubular goods were to otherwise increase from current levels, our tubular services segment could be adversely affected to the extent that we would 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 an 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.

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 30% (13% excluding Canada) of our consolidated revenue in the year ended December 31, 2011. Risks associated with our operations in foreign areas include, but are not limited to:

• war and civil disturbances or other risks that may limit or disrupt markets;

• expropriation, confiscation or nationalization of assets;

• renegotiation or nullification of existing contracts;

• foreign exchange restrictions;

• foreign currency fluctuations;

• foreign taxation;

• the inability to repatriate earnings or capital;

• changing political conditions;

• changing foreign and domestic monetary policies;

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• social, political, military and economic situations in foreign areas where we do business and the possibilities of war, other armed conflict or terrorist attacks; and

• regional economic downturns.

Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete.

Our international business operations also include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to the same ethics related laws and regulations such as the Foreign Corrupt Practices Act in the U.S. and the Bribery Act in the U.K., can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that certain ethics related laws and regulations prohibit us from using. For example, our non-U.S. competitors may not be 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, like the U.S. and the U.K., have adopted 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 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 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:

• issuance of administrative, civil and criminal penalties;

• denial or revocation of permits or other authorizations;

• reduction or cessation in operations; and

• performance of site investigatory, remedial or other corrective actions.

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

Climate change is receiving 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.

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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:

• result in increased costs associated with our operations and our customers’ operations;

• increase other costs to our business;

• adversely impact overall drilling activity in the areas in which we operate;

• reduce the demand for carbon-based fuels; and

• reduce the demand for our services.

Any adoption of these or similar proposals by foreign, U.S. federal, regional or state governments mandating a substantial reduction in greenhouse gas emissions and implementation of the Kyoto Protocol (the Copenhagen Accord,) or other foreign, U.S. federal, regional or state requirements or other efforts to regulate greenhouse gas emissions, 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.

Currently proposed legislative changes, including changes to tax laws and regulations, could materially, negatively impact the Company, increase the costs of doing business and decrease the demand for our products.

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

• cap and trade system for emissions;

• increase environmental limits on exploration and production activities;

• repeal of expensing of intangible drilling costs;

• increase of the amortization period for geological and geophysical costs to seven years;

• repeal of percentage depletion;

• limits on hydraulic fracturing or disposal of hydraulic fracturing fluids;

• repeal of the domestic manufacturing deduction for oil and natural gas production;

• repeal of the passive loss exception for working interests in oil and natural gas properties;

• repeal of the credits for enhanced oil recovery projects and production from marginal wells;

• repeal of the deduction for tertiary injectants;

• changes to the foreign tax credit limitation calculation; and

• changes to healthcare rules and regulations.

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, Australia, 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

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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 our ability to provide services in the second and, to a lesser extent, third quarters. During the Australian rainy season, generally between the months of November and April, our accommodations operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Severe winter weather conditions in the Rocky Mountain region can restrict access to work areas for our well site services and accommodations segment operations. 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. Cyclones can affect our operations in Australia.

We are exposed to risk relating to subcontractors’ performance in some of our projects.

In many cases, we subcontract the performance of parts of our operations to subcontractors. While we seek to obtain appropriate indemnities and guarantees from these subcontractors, we remain ultimately responsible for the performance of our subcontractors. Industrial disputes, natural disasters, financial failure or default or inadequate performance in the provision of services, or the inability to provide services by such subcontractors has the potential to materially adversely affect us.

Our inability to control the inherent risks of identifying, acquiring and integrating businesses, including any related increases in debt or issuances of equity securities, 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:

• retaining key employees of acquired businesses;

• retaining and attracting new customers of acquired businesses;

• retaining supply and distribution relationships key to the supply chain;

• increased administrative burden;

• developing our sales and marketing capabilities;

• managing our growth effectively;

• potential impairment resulting from the overpayment for an acquisition;

• integrating operations;

• managing tax and foreign exchange exposure;

• operating a new line of business; and

• increased logistical problems common to large, expansive operations.

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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 may not have adequate insurance for potential liabilities.

Our operations are subject to many hazards. We face the following risks under our insurance coverage:

• we may not be able to continue to obtain insurance on commercially reasonable terms;

• we may be faced with types of liabilities that will not be covered by our insurance, such as damages from environmental contamination or terrorist attacks;

• the dollar amount of any liabilities may exceed our policy limits;

• the counterparties to our insurance contracts may pose credit risks; and

• we may incur losses from interruption of our business that exceed our insurance coverage.

Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position.

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 policies. 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.

Our concentration of customers in two industries may impact our overall exposure to credit risk.

The majority of our customers operate in the energy or mining industries. This concentration of customers in two industries may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.

Our common stock price has been volatile.

The market price of common stock of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly (2011 low of $46.95 per share; 2011 high of $85.50 per share) in the past, and we expect it to continue to remain highly volatile given the cyclical nature of our industry.

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.

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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 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 offshore products segment 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 cancellations by customers 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 to the total revenues reflected in our backlog once a project is cancelled. If we experience significant project terminations, suspensions or scope adjustments to contracts included in our backlog, our financial condition, results of operations and cash flows may be adversely impacted.

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 accommodations business in Canada and Australia. When these events occur, our cost structure increases and our growth potential could be impaired.

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

30

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.

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 technologies, which address similar or improved solutions to our existing technology. Should our technologies, particularly in offshore products or in our rental tools and services business, become the less attractive solution, our operations and profitability would be negatively impacted.

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.

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.

If we were to lose a significant supplier of our tubular goods, we could be adversely affected.

During 2011, we purchased 58% of our total tubular goods from a single domestic supplier and 85% of our total OCTG purchases were from three suppliers. If we were to lose any of these suppliers or if production at one or more of the suppliers was interrupted, our tubular services segment’s 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 could 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 accommodations assets, 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 for or utilization of our assets and services, which could adversely impact our operations and profits.

In addition, we have significantly increased our accommodations capacity in the oil sands region over the past six years and in Australia over the past year based on our expectation for current and future customer demand for accommodations in these areas. 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 or Australia declines significantly, demand and/or pricing for our accommodations could decrease, negatively impacting the profitability of our accommodations segment.

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We might be unable to protect our intellectual property rights.

We rely on a variety of intellectual property rights that we use in our offshore products and well site services segments, particularly our patents relating to our FlexJoint^® and Merlin 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.

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.

Employee and customer labor problems could adversely affect us.

We are party to collective bargaining agreements covering 1,567 employees in Canada, 525 employees in Australia, 16 employees in the United Kingdom and 16 employees in Argentina. In addition, our accommodations facilities serving oil sands development work in Northern Alberta, Canada and mining operations in Australia 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.

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Provisions contained in our certificate of incorporation and bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our stockholders to sell their shares for a premium.

Provisions contained in our certificate of incorporation and bylaws, such as a classified board, limitations on the removal of directors, on stockholder proposals at meetings of stockholders and on stockholder action by written consent and the inability of stockholders to call special meetings, could make it more difficult for a third party to acquire control of our company. Our certificate of incorporation also authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could increase the difficulty for a third party to acquire us, which may reduce or eliminate our stockholders’ ability to sell their shares of common stock at a premium.

Item 1B.    Unresolved Staff Comments

None.

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Item 2.    Properties

The following table presents information about our principal properties and facilities. For a discussion about how each of our business segments utilizes its respective properties, please see Part I, Item 1, “Business.” Except as indicated below, we own all of these properties or facilities.

Location	Approximate Square Footage/Acreage	Description
United States:
Houston, Texas (lease)	21,420	Principal executive offices
Arlington, Texas (own and lease)	43 acres	Various contiguous office, manufacturing and warehouse facilities located in thirteen buildings
Houston, Texas	25 acres	Offshore products office, manufacturing facility and yard
Houston, Texas	22 acres	Offshore products manufacturing facility and yard
Houston, Texas (lease)	50,750	Offshore products service facility and office
Houma, Louisiana	40 acres	Offshore products manufacturing facility and yard
Houma, Louisiana (lease)	20,000	Offshore products manufacturing facility and yard
Tulsa, Oklahoma	74,600	Molding facility for offshore products
Tulsa, Oklahoma (lease)	14,000	Molding facility for offshore products
Lampasas, Texas	48,500	Molding facility for offshore products
Lampasas, Texas (lease)	20,000	Warehouse for offshore products
Crosby, Texas	109 acres	Tubular yard
Midland, Texas	69 acres	Tubular yard
Godley, Texas	31 acres	Tubular yard
Montoursville, Pennsylvania	24 acres	Tubular yard
Searcy, Arkansas	14 acres	Tubular yard
Tulsa, Oklahoma (lease)	11,955	Tubular services business office
Houston, Texas (lease)	9,945	Tubular services business office
Dickinson, North Dakota (lease)	26 acres	Accommodations facility and yard
Carrizo Springs, Texas (lease)	20 acres	Accommodations facility
Johnstown, Colorado	13 acres	Accommodations manufacturing
Belle Chasse, Louisiana (own and lease)	10 acres	Accommodations manufacturing
		facility and yard
Big Piney, Wyoming (lease)	7 acres	Accommodations facility and yard
Stanley, North Dakota (lease)	7 acres	Accommodations facility
Englewood, Colorado (lease)	5,480	Accommodations office
Odessa, Texas	22 acres	Office, shop, warehouse and yard in support of drilling operations for well site services
Casper, Wyoming	7 acres	Office, shop and yard in support of drilling operations for well site services
Canada:
Fort McMurray, Alberta (Wapasu Creek and Henday Lodges)(lease)	240 acres	Accommodations facility
Fort McMurray, Alberta (Pebble Beach) (lease)	140 acres	Accommodations facility
Fort McMurray, Alberta (Conklin Lodge)(lease)	135 acres	Accommodations facility
Fort McMurray, Alberta (Beaver River and Athabasca Lodges) (lease)	128 acres	Accommodations facility
Fort McMurray, Alberta (Christina Lake Lodge)	45 acres	Accommodations facility
Edmonton, Alberta	33 acres	Accommodations manufacturing facility
Grimshaw, Alberta (lease)	20 acres	Accommodations equipment yard
Grande Prairie, Alberta	15 acres	Accommodations facility and equipment yard
Nisku, Alberta	9 acres	Accommodations manufacturing facility
Edmonton, Alberta (lease)	86,376	Accommodations office and warehouse
Edmonton, Alberta (lease)	16,130	Accommodations office
Spruce Grove, Alberta	15,000	Accommodations facility and equipment yard

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Location	Approximate Square Footage/Acreage	Description
Australia:
Copabella, Queensland, Australia	198 acres	Accommodations facility
Calliope, Queensland, Australia	124 acres	Accommodations facility
Narrabri, New South Wales, Australia	82 acres	Accommodations facility
Nebo, Queensland, Australia	51 acres	Accommodations facility
Middlemount, Queensland, Australia	37 acres	Accommodations facility
Dysart, Queensland, Australia	34 acres	Accommodations facility
Karratha, Western Australia, Australia	34 acres	Accommodations facility
Kambalda, Western Australia, Australia	27 acres	Accommodations facility
Ormeau, Queensland, Australia	3 acres	Accommodations manufacturing facility
Yatala, Queensland, Australia	2 acres	Accommodations manufacturing facility
Sydney, New South Wales, Australia (lease)	16,899	Accommodations office
Other International:
Aberdeen, Scotland (lease)	15 acres	Offshore products manufacturing facility and yard
Macaé, Brazil (lease)	6 acres	Offshore products manufacturing
		facility and yard
Singapore (lease)	155,398	Offshore products manufacturing facility
Singapore (lease)	71,516	Offshore products manufacturing facility
Bathgate, Scotland	3 acres	Offshore products manufacturing facility and yard
Barrow-in-Furness, England (own and lease)	63,300	Offshore products service facility and yard
Rayong Province, Thailand (lease)	28,000	Offshore products service and manufacturing facility

We also have eight tubular sales offices and a total of 56 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 believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing additional suitable space upon expiration of our current lease terms.

Item 3. Legal Proceedings

We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Common Stock Information

Our authorized common stock consists of 200,000,000 shares of common stock. There were 51,341,686 shares of common stock outstanding as of February 14, 2012. The approximate number of record holders of our common stock as of February 14, 2012 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 14, 2012 was $83.78 per share.

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

	Sales Price
	High		Low
2010:
First Quarter	$	48.77	$	33.65
Second Quarter		51.20		35.99
Third Quarter		47.89		38.24
Fourth Quarter		65.98		46.21
2011:
First Quarter	$	78.43	$	60.76
Second Quarter		83.13		68.49
Third Quarter		87.00		49.40
Fourth Quarter		78.53		44.77

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 Part II, 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.

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PERFORMANCE GRAPH

The following performance graph and chart compare the cumulative total stockholder return on the Company’s common stock to the cumulative total return on the Standard & Poor’s 500 Stock Index and Philadelphia OSX Index, an index of oil and gas related companies that represent an industry composite of the Company’s peer group, for the period from December 31, 2006 to December 31, 2011. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2006 and assume the reinvestment of all dividends.

Oil States International – NYSE

	Cumulative Total Return
	12/06		12/07		12/08		12/09		12/10		12/11
OIL STATES INTERNATIONAL, INC.	$	100.00	$	105.86	$	57.99	$	121.92	$	198.84	$	236.94
S & P 500		100.00		105.49		66.47		84.06		96.73		98.77
PHLX OIL SERVICE SECTOR (OSX)		100.00		151.52		61.40		99.57		126.39		113.02

* $100 invested on December 31, 2006 in stock or index-including reinvestment of dividends. Fiscal year ending December 31st.

(1) This graph is not “soliciting material,” is not deemed filed with the Commission and is not to be incorporated by reference in any filing by us under the Securities Act, or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.

(2) The stock price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.

Prepared by Zacks Investment Research, Inc. Used with permission. All rights reserved. Copyright 1980-2012.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchases

None.

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Item 6. SelectedFinancial Data

The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2011. The following data should be read in conjunction with Part II, 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 Part II, Item 8, “Financial Statements” of this Annual Report on Form 10-K.

Selected Financial Data

(In thousands, except per share amounts)

	Year Ended December 31,
	2011			2010			2009			2008			2007
Statement of Income Data:
Revenues	$	3,479,180		$	2,411,984		$	2,108,250		$	2,948,457		$	2,088,235
Costs and Expenses:
Product costs, service and other costs		2,599,267			1,874,294			1,640,198			2,234,974			1,602,213
Selling, general and administrative expenses		182,434			150,865			139,293			143,080			118,421
Depreciation and amortization expense		188,147			124,202			118,108			102,604			70,703
Impairment of goodwill		—			—			94,528			85,630			—
Other operating (income) expense		1,809			7,041			(2,606	)		(1,586	)		(888	)
Operating income		507,523			255,582			118,729			383,755			297,786
Interest expense, net of capitalized interest		(57,506	)		(16,274	)		(15,266	)		(23,585	)		(23,610	)
Interest income		1,700			751			380			3,561			3,508
Equity in earnings (loss) of unconsolidated affiliates		(163	)		239			1,452			4,035			3,350
Gain on sale of workover services business and resulting equity investment		—			—			—			6,160			12,774
Other income (expense)		3,515			330			414			(476	)		1,213
Income before income taxes		455,069			240,628			105,709			373,450			295,021
Income tax provision(1)		(131,647	)		(72,023	)		(46,097	)		(154,151	)		(94,945	)
Net income	$	323,422		$	168,605		$	59,612		$	219,299		$	200,076
Less: Net income attributable to noncontrolling interest		969			587			498			446			284
Net income attributable to Oil States International, Inc.	$	322,453		$	168,018		$	59,114		$	218,853		$	199,792
Net income per share attributable to Oil States International, Inc:
Basic	$	6.30		$	3.34		$	1.19		$	4.41		$	4.04
Diluted	$	5.86		$	3.19		$	1.18		$	4.26		$	3.92
Average common shares outstanding
Basic		51,163			50,238			49,625			49,622			49,500
Diluted		55,007			52,700			50,219			51,414			50,911

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	Year Ended December 31,
	2011			2010			2009			2008			2007
Other Data:
EBITDA, as defined(2)	$	698,053		$	379,766		$	238,205		$	495,632		$	385,542
Capital expenditures, including capitalized interest		487,482			182,207			124,488			247,384			239,633
Acquisitions of businesses, net of cash acquired		2,412			709,575			(18	)		29,835			103,143
Net cash provided by operating activities		215,913			230,922			453,362			257,464			247,899
Net cash used in investing activities, including capital expenditures		(488,955	)		(889,680	)		(102,608	)		(246,094	)		(310,836	)
Net cash provided by (used in) financing activities		257,888			649,032			(296,773	)		(1,666	)		60,632

	At December 31,
	2011		2010		2009		2008		2007
Balance Sheet Data:
Cash and cash equivalents	$	71,721	$	96,350	$	89,742	$	30,199	$	30,592
Total current assets Property, plant and equipment, net		1,489,659 1,557,088		1,100,004 1,252,657		925,568 749,601		1,237,484 695,338		865,667 586,910
Total assets		3,703,641		3,015,999		1,932,386		2,298,518		1,928,669
Long-term debt and capital leases, excluding current portion and 2 3/8% Notes		971,621		731,732		8,215		299,948		312,102
2 3/8% contingent convertible senior subordinated notes		170,884		163,108		155,859		149,110		142,827
Total stockholders’ equity		1,963,272		1,628,933		1,382,066		1,235,541		1,105,058

(1) Our effective tax rate increased in 2008 and 2009 due to the impairment of non-deductible goodwill.

(2) The term EBITDA as defined consists of net income plus interest expense, net, income taxes, depreciation and amortization. EBITDA as defined is not a measure of financial performance under generally accepted accounting principles. You should not consider it in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of profitability or liquidity. Additionally, EBITDA as defined may not be comparable to other similarly titled measures of other companies. The Company has included EBITDA as defined as a supplemental disclosure because its management believes that EBITDA as defined provides useful information regarding its ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing its operating performance with the performance of other companies that have different financing and capital structures or tax rates. The Company uses EBITDA as defined to compare and to monitor the performance of its business segments to other comparable public companies and as one of the primary measures to benchmark for the award of incentive compensation under its annual incentive compensation plan.

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We believe that net income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA as defined with our net income, as derived from our financial information (in thousands):

	Year Ended December 31,
	2011		2010		2009		2008		2007
Net income attributable to Oil States
International, Inc.	$	322,453	$	168,018	$	59,114	$	218,853	$	199,792
Depreciation and amortization expense		188,147		124,202		118,108		102,604		70,703
Interest expense, net		55,806		15,523		14,886		20,024		20,102
Income tax provision		131,647		72,023		46,097		154,151		94,945
EBITDA, as defined	$	698,053	$	379,766	$	238,205	$	495,632	$	385,542

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business operations. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of numerous factors, including the known material factors set forth in Part I, Item 1A, “Risk Factors.” 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.

Macroeconomic Environment and Outlook

We provide a broad range of products and services to the oil and gas industry through our accommodations, offshore products, well site services and tubular services business segments. In our accommodations segment, we support both the oil and gas and mining industries. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to spend capital on the exploration for and development of oil, natural gas, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, demand for our products and services is highly sensitive to current and expected commodity prices, principally that of crude oil and, to a lesser extent, natural gas and coal.

During 2011 and in early 2012, crude oil prices exhibited volatility due to concerns about potential decreases in demand caused by the slowed momentum of the global economic recovery. However, in the fourth quarter of 2011, the price of crude oil increased as positive economic news related to solid growth rates projected in China and other emerging markets, consumer spending, employment data and U.S. consumer confidence indicated that an economic recovery was underway. In addition, potential supply interruptions were feared as Iran threatened to shut down the Strait of Hormuz as tensions mounted in the region between Iran and other nations regarding proposed sanctions related to Iran’s nuclear programs. The Organization of Petroleum Exporting Countries (OPEC) eased some of these concerns by announcing that member nation Saudi Arabia and others would be ready to provide additional supply in the event of a blockage of the distribution channel. Despite signs of an improving economy in the United States, the world’s largest consumer of crude oil, global economic risks remain due to fiscal and financial uncertainty in various European countries, a prolonged level of relatively high unemployment in the U.S. and other advanced economies and inflation risks in certain emerging markets. The price of crude oil in January 2012 was trading at approximately $99 per barrel for West Texas Intermediates (WTI) crude and around $111 per barrel for Intercontinental Exchange (ICE) Brent crude.

Prices for natural gas continue to be weak due to the rise in production of unconventional gas resources in North America, largely due to increases in onshore shale production resulting from technological advancements in horizontal drilling and hydraulic fracturing. Natural gas prices have traded below $2.50 per Mcf during January 2012. Natural gas inventories in the U.S. continue to be over-stocked, particularly given an unseasonably

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warm start to the winter season. Prolonged increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, will likely constrain prices for natural gas.

Various oil and gas industry analysts have projected that 2012 global exploration and production expenditures are expected to increase over calendar year 2011 levels. North American capital spending plans are expected to be focused in onshore areas while international exploration and production budgets are expected to primarily be spent offshore.

Overview

Activity for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, activity for our well site services and tubular services segments responds to shorter-term movements in oil and natural gas prices and, specifically, changes in North American drilling and completion activity. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the United States and internationally.

Generally, our oil sands and mining accommodations customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of 10 to in excess of 30 years and, consequently, these investments are dependent on those customers’ longer-term view of commodity demand and prices. Oil sands development activity has increased in the past year and has had a positive impact on our accommodations segment. Recent announcements of new and expanded oil sands projects will create the opportunity for extensions of existing accommodations contracts and incremental accommodations contracts for us in Canada. In addition, several major oil companies and national oil companies have announced joint ventures to develop oil sands leases that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. Our Australian accommodations business is significantly influenced by increased metallurgical coal demand, especially from Japan, China and India. Metallurgical coal prices in China have strengthened recently and Chinese metallurgical coal demand is expected to increase in 2012 compared to 2011 and could result in another annual metallurgical coal import record. We are expanding our Australian accommodations capacity to meet this increasing demand. Accommodations deployed to support onshore U.S. drilling activity in several of the active shale play regions have also favorably contributed to our results.

Our offshore products segment provides highly engineered products for offshore oil and natural gas drilling and production systems and facilities. Sales of our offshore products and services depend primarily upon development of infrastructure for 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 spending, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices.

In our well site services business segment, we predominantly provide rental tools and services and, to a lesser extent, land drilling services. Our rental tools and services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the rental tools and services business is dependent primarily upon the level and complexity of drilling, completion and workover activity throughout North America. Well complexity has increased as the number of productive zones completed in connection with horizontal drilling has increased. 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 drill both oil and natural gas wells.

Through our tubular services segment, we distribute a broad range of casing and tubing used in the drilling and completion of oil and natural gas wells primarily in North America. Accordingly, sales and gross margins in our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled, movements in global steel input prices and the overall industry level of OCTG inventory and pricing. Historically, tubular services’ gross margin generally expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices.

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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 tools and services 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.

	Average Rig Count for Year Ended December 31,
	2011		2010		2009		2008		2007
U.S. Land — Oil		966		573		270		377		294
U.S. Land — Natural gas and other		877		937		772		1,436		1,401
U.S. Offshore		32		31		44		65		73
Total U.S.		1,875		1,541		1,086		1,878		1,768
Canada		423		351		221		379		343
Total North America		2,298		1,892		1,307		2,257		2,111

The rig count fell precipitously in the first half of 2009 in response to the impact of the global economic downturn which negatively impacted energy prices but has substantially recovered from its June 2009 low. The average North American rig count for the year ended December 31, 2011 increased by 406 rigs, or 21%, compared to the average for the year ended December 31, 2010.

A factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and, to a lesser extent, the exchange rate between the U.S. dollar and the Australian dollar. Our accommodations segment has derived a majority of its revenues and operating income in Canada and, more recently, Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the year 2011, the Canadian dollar was valued at an average exchange rate of U.S. $1.01 compared to U.S. $0.97 for 2010, an increase of 4%. This strengthening of the Canadian dollar had a positive impact on the translation of earnings generated from our Canadian subsidiaries and, therefore, the financial results of our accommodations segment. For the year 2011, the Australian dollar was valued at average exchange rate of U.S. $1.03 compared to U.S. $.92 for 2010, an increase of 12%.

Steel and steel input prices influence the pricing decisions of our OCTG suppliers, thereby impacting the pricing and margins of our tubular services segment. Steel prices on a global basis declined precipitously during the recession in 2009. Industry inventories increased materially as the rig count declined and imports remained at high levels. These developments in the OCTG marketplace had a material detrimental impact on OCTG pricing and, accordingly, on our revenues and margins realized during the last half of 2009 in our tubular services segment. These negative trends moderated in 2010 because of a reduction in imports, largely due to the imposition of trade sanctions on Chinese OCTG imports coupled with increases in the U.S. rig count. During 2011, OCTG marketplace supply and demand became more balanced. Increased supplies of OCTG have met the increased demand created by expanded drilling activity. During 2011, U.S. mills began increasing production and imports of steel increased throughout 2011, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. This increase in supply has been in response to the 21% year-over-year increase in the drilling rig count in the United States. Recent global steel prices have increased affecting the raw material costs of our OCTG suppliers. To date, we have realized modest OCTG price increases, which we have been able to pass through to our customers. 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 four to five months’ supply currently, which is considered closer to a normalized level when measured against historical levels. We remain focused on working capital management in our tubular services segment and will continue to monitor industry inventory levels, forecasted drilling and completion activity and OCTG prices.

While global demand for oil and natural gas are significant factors influencing our business generally, certain other factors also influence our business, such as the pace of worldwide economic growth and the recovery in U.S. Gulf of Mexico drilling following the lifting of the government imposed drilling moratorium.

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Drilling activity in the U.S. Gulf of Mexico remains well below historical levels as a result of unprecedented events in the U.S. Gulf of Mexico following the Macondo well incident and resultant oil spill. A rescission of a moratorium on offshore drilling activity was effective in late 2010; however, increases in activity were delayed by adjustments in operating procedures, compliance certifications, and lead times for permits and inspections, as a result of changes in the regulatory environment. In addition, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production. Uncertainties and delays caused by the new regulatory environment continued to have an overall negative effect on Gulf of Mexico drilling activity in 2011. Recently, however, Gulf of Mexico drilling activity has shown signs of a slow but steady recovery as permitting levels have been steadily improving. New well permitting in the second half of 2011 showed significant improvement over the first half of 2011 as regulators and operators appear to be adapting to the new permitting process.

We continue to monitor the global economy, the demand for crude oil, coal and natural gas and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. Our capital expenditures in 2011 totaled $487 million compared to 2010 capital expenditures of $182 million. Our 2011 capital expenditures included funding to expand several of our Canadian and Australian accommodations facilities, and to increase our fleet of modular, mobile camp assets in Canada and the U.S. and to complete projects in progress at December 31, 2010, including (i) the construction of the Henday Lodge accommodations facility in the Canadian oil sands and (ii) continued expansion of our Wapasu Creek and Athabasca Lodge accommodations facilities in the Canadian oil sands. Additional capital was committed as of December 31, 2010 to expand and replace rental tool assets which were delivered in 2011. Approximately 70% of our total 2011 capital expenditures was spent in our accommodations segment. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on a careful evaluation of both the market outlook and industry fundamentals.

Recent Acquisitions

On November 1, 2011, we purchased an open camp accommodations facility located in Carrizo Springs, Texas for total consideration of $2.2 million. This facility will provide accommodations support to customers working in the Eagle Ford Shale basin. The operations of the Carrizo Springs facility have been included in our accommodations segment since its date of acquisition.

On December 30, 2010, we acquired all of the ordinary shares of The MAC Services Group Limited (The MAC), through a Scheme of Arrangement (the Scheme) under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the Australian natural resources market. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. The total purchase price was $638 million, net of cash acquired plus debt assumed of $87 million. The MAC’s operations have been included in our accommodations segment beginning in 2011.

On December 20, 2010, we also acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million and estimated contingent consideration of $3.6 million. Headquartered in Vernal, Utah, with operations in the Rockies and the Bakken Shale region, Mountain West provides remote site workforce accommodations to the oil and gas industry. Mountain West has been included in our accommodations segment since its date of acquisition.

The Company funded the acquisitions of The MAC and Mountain West with cash on hand and draws under our senior secured credit facilities. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.

On October 5, 2010, we purchased all of the equity of Acute Technological Services, Inc. (Acute) for total consideration of $30.2 million. Headquartered in Houston, Texas with additional operations in Brazil, Acute provides metallurgical and welding engineering, consulting and services to the oil and gas industry in support of critical, complex subsea component manufacturing and deepwater riser fabrication on a global basis. Acute has been included in our offshore products segment since its date of acquisition. We funded the Acute acquisition using cash on hand and draws under our then existing credit facility.

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Consolidated Results of Operations (in millions)

	YEARS ENDED December 31,
							Variance					Variance
							2011 vs. 2010					2010 vs. 2009
	2011			2010			$		%			2009 _			$_			%
Revenues
Well site services -
Rental tools and services	$	488.0		$	343.0		$	145.0		42	%	$	234.1		$	108.9			47	%
Drilling services		165.9			133.2			32.7		25	%		71.2			62.0			87	%
Total well site services		653.9			476.2			177.7		37	%		305.3			170.9			56	%
Accommodations		864.7			537.7			327.0		61	%		481.4			56.3			12	%
Offshore products		585.8			428.9			156.9		37	%		509.4			(80.5	)		(16	%)
Tubular services		1,374.8			969.2			405.6		42	%		812.2			157.0			19	%
Total	$	3,479.2		$	2,412.0		$	1,067.2		44	%	$	2,108.3		$	303.7			14	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services—
Rental tools and services	$	298.4		$	220.1		$	78.3		36	%	$	169.6		$	50.5			30	%
Drilling services		122.7			105.5			17.2		16	%		58.2			47.3			81	%
Total well site services		421.1			325.6			95.5		29	%		227.8			97.8			43	%
Accommodations		456.4			314.4			142.0		45	%		278.7			35.7			13	%
Offshore products		430.0			316.5			113.5		36	%		377.1			(60.6	)		(16	%)
Tubular services		1,291.8			917.8			374.0		41	%		756.6			161.2			21	%
Total	$	2,599.3		$	1,874.3		$	725.0		39	%	$	1,640.2		$	234.1			14	%
Gross margin
Well site services—
Rental tools and services	$	189.6		$	122.9		$	66.7		54	%	$	64.5		$	58.4			91	%
Drilling services		43.2			27.7			15.5		56	%		13.0			14.7			113	%
Total well site services		232.8			150.6			82.2		55	%		77.5			73.1			94	%
Accommodations		408.3			223.3			185.0		83	%		202.7			20.6			10	%
Offshore products		155.8			112.4			43.4		39	%		132.3			(19.9	)		(15	%)
Tubular services		83.0			51.4			31.6		61	%		55.6			(4.2	)		(8	%)
Total	$	879.9		$	537.7		$	342.2		64	%	$	468.1		$	69.6			15	%
Gross margin as a percentage of revenues
Well site services—
Rental tools and services		39	%		36	%							28	%
Drilling services		26	%		21	%							18	%
Total well site services		36	%		32	%							25	%
Accommodations		47	%		42	%							42	%
Offshore products		27	%		26	%							26	%
Tubular services		6	%		5	%							7	%
Total		25	%		22	%							22	%

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YEAR ENDED DECEMBER 31, 2011 COMPARED TO YEAR ENDED DECEMBER 31, 2010

We reported net income attributable to the Company for the year ended December 31, 2011 of $322.5 million, or $5.86 per diluted share. These results compare to net income attributable to the Company of $168.0 million, or $3.19 per diluted share, reported for the year ended December 31, 2010.

Revenues.    Consolidated revenues increased $1.1 billion, or 44%, in 2011 compared to 2010.

Our well site services segment revenues increased $177.7 million, or 37%, in 2011 compared to 2010. This increase was primarily due to significantly increased rental tools and services revenues. Our rental tools and services revenues increased $145.0 million, or 42%, primarily due to increased demand for completion services supporting the increase in the U.S. rig count, a more favorable mix of higher value rentals and services, increased equipment utilization, additional capital investment in rental equipment and better pricing. Our drilling services revenues increased $32.7 million, or 25%, in 2011 compared to 2010 primarily as a result of increases in pricing, with average day rates rising to $16.4 thousand per day in 2011 from $14.2 thousand per day in 2010, and increased utilization of our rigs from an average of approximately 72% in 2010 to an average of approximately 82% in 2011.

Our accommodations segment reported revenues in 2011 that were $327.0 million, or 61%, above 2010. The increase in accommodations revenue resulted from the contribution from the fourth quarter 2010 acquisitions of The MAC and Mountain West along with increased revenues generated from expanded room capacity in Canada and Australia. Revenues and average available rooms for our oil sands lodges increased 40% and 30%, respectively, in 2011 compared to 2010.

Our offshore products segment revenues increased $156.9 million, or 37%, in 2011 compared to 2010. This increase was primarily the result of higher demand for production equipment and elastomer products along with contributions from the acquisition of Acute.

Tubular services segment revenues increased $405.6 million, or 42%, in 2011 compared to 2010. This increase was a result of an increase in tons shipped from 502,800 tons in 2010 to 699,000 tons in 2011, an increase of 196,200 tons, or 39%, driven by increased U.S. drilling and completion activity.

Cost of Sales and Service.    Our consolidated cost of sales increased $725.0 million, or 39%, in 2011 compared to 2010 as a result of increased cost of sales at our tubular services segment of $374.0 million, or 41%, an increase at our accommodations segment of $142.0 million, or 45%, an increase at our offshore products segment of $113.5 million, or 36%, and an increase at our well site services segment of $95.5 million, or 29%. These cost of sales increases were directly related to the increases in segmental revenues. Our consolidated gross margin as a percentage of revenues increased from 22% in 2010 to 25% in 2011 primarily due to the increased proportion of relatively higher margin accommodations and well site services segment revenues in 2011 compared to 2010 and higher margins realized in our accommodations and well site services segments, partially offset by an increased proportion of relatively lower margin tubular services segment revenues in 2011 compared to 2010.

Our well site services segment cost of sales increased $95.5 million, or 29%, in 2011 compared to 2010 primarily as a result of a $78.3 million, or 36%, increase in rental tools and services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 32% in 2010 to 36% in 2011. Our rental tools and services gross margin as a percentage of revenues increased from 36% in 2010 to 39% in 2011 primarily due to a more favorable mix of higher value rentals and services and improved pricing along with higher fixed cost absorption as a result of increased rental tool utilization. Our drilling services cost of sales increased $17.2 million, or 16%, in 2011 compared to 2010. Our drilling services gross margin as a percentage of revenues increased from 21% in 2010 to 26% in 2011 primarily due to an increase in day rates, rig utilization and improved cost absorption.

Our accommodations segment cost of sales increased $142.0 million, or 45%, in 2011 compared to 2010 primarily as a result of operating costs associated with the acquisitions of The MAC and Mountain West and a $36.2 million, or 12%, increase in the cost of sales of our Canadian accommodations business primarily due to increased revenues and room capacity. Our accommodations segment gross margin as a percentage of revenues increased from 42% in 2010 to 47% in 2011 primarily due to higher margins realized on our lodges and villages.

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Our offshore products cost of sales increased $113.5 million, or 36%, in 2011 compared to 2010 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues increased modestly, 26% in 2010 compared to 27% in 2011.

Tubular services segment cost of sales increased by $374.0 million, or 41%, in 2011 compared to 2010 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues increased from 5% in 2010 to 6% in 2011 due primarily to a 2% increase in revenue per ton.

Selling, General and Administrative Expenses.     Selling, general and administrative (SG&A) expense increased $31.6 million, or 21%, in 2011 compared to 2010 due primarily to the acquisition of The MAC, increased employee-related costs, higher SG&A costs in our Canadian accommodations business due to the strengthening of the Canadian dollar, increased third-party professional fees and increased commissions expense. SG&A was 5.2% of revenues in 2011 compared to 6.3% of revenues in 2010.

Depreciation and Amortization.    Depreciation and amortization expense increased $63.9 million, or 51%, in 2011 compared to 2010 due primarily to $50.6 million in depreciation and amortization expense associated with acquisitions made in the fourth quarter of 2010 and capital expenditures made in 2010 and 2011, largely related to investments made in our Canadian accommodations business.

Operating Income.    Consolidated operating income doubled to $251.9 million in 2011 compared to 2010 primarily as a result of an increase in operating income from our well site services segment of $93.3 million, or 195%, largely due to a more favorable mix, improved pricing and increased activity in our rental tools and services business coupled with an increase in operating income as a result of the addition of The MAC. In addition, operating income from our offshore products segment increased $34.0 million, or 56%, in 2011 compared to 2010 and operating income from our tubular services segment increased $28.5 million, or 79%, primarily as a result of the increase in tons shipped. Operating income in 2011 and 2010 included $2.2 million and $7.0 million, respectively, in acquisition related expenses.

Interest Expense and Interest Income.    Net interest expense increased by $40.3 million, or 260%, in 2011 compared to 2010 due to increased debt levels, interest expense on the newly issued 6 1/2% senior unsecured notes due in 2019 (6 1/2% Notes), and an increase in non-cash interest expense as a result of the amortization of debt issuance costs on our revolving credit, term loan facilities and the 6 1/2% Notes. The weighted average interest rate on borrowings outstanding under the Company’s revolving credit and term loan facilities was 3.1% in 2011 compared to 3.6% in 2010. Interest income increased as a result of increased cash balances in interest bearing accounts.

Income Tax Expense.    Our income tax provision for 2011 totaled $131.6 million, or 28.9% of pretax income, compared to $72.0 million, or 29.9% of pretax income, for 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010, partially offset by an increase in state taxes.

YEAR ENDED DECEMBER 31, 2010 COMPARED TO YEAR ENDED DECEMBER 31, 2009

We reported net income attributable to the Company for the year ended December 31, 2010 of $168.0 million, or $3.19 per diluted share. These results compare to net income attributable to the Company of $59.1 million, or $1.18 per diluted share, reported for the year ended December 31, 2009. The net income attributable to the Company for 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 and services reporting unit.

Revenues.    Consolidated revenues increased $303.7 million, or 14%, in 2010 compared to 2009.

Our well site services segment revenues increased $170.9 million, or 56%, in 2010 compared to 2009. This increase was primarily due to increased rental tools and services revenues and significantly increased rig utilization in our drilling services operations. Our rental tools and services revenues increased $108.9 million, or 47%, primarily due to increased demand for completion services with the increase in the U.S. rig count, a more favorable mix of higher value equipment, increased equipment utilization and improved pricing. Our drilling services revenues increased $62.0 million, or 87%, in 2010 compared to 2009 primarily as a result of increased utilization of our rigs. Utilization of our drilling rigs increased from an average of approximately 37% in 2009 to an average of approximately 71% in 2010.

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Our accommodations segment reported revenues in 2010 that were $56.3 million, or 12%, above 2009. The increase in accommodations revenue resulted from increased activity at our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, the expansion of two of these facilities and the strengthening of the Canadian dollar versus the U.S. dollar, partially offset by a $62.7 million decrease in third-party accommodations manufacturing revenues.

Our offshore products segment revenues decreased $80.5 million, or 16%, in 2010 compared to 2009. This decrease was primarily due to lower starting backlog levels, a decrease in subsea pipeline revenues and rig and vessel equipment revenues driven principally by reductions in our customers’ spending caused by deferrals and delays of deepwater development projects and capital upgrades.

Tubular services segment revenues increased $157.0 million, or 19%, in 2010 compared to 2009. This increase was a result of an increase in tons shipped from 330,800 in 2009 to 502,800 in 2010 driven by increased drilling activity, an increase of 172,000 tons, or 52%, partially offset by a 22% decrease in realized revenues per ton shipped in 2010.

Cost of Sales and Service.    Our consolidated cost of sales increased $234.1 million, or 14%, in 2010 compared to 2009. This increase was primarily a result of increased cost of sales at our tubular services segment of $161.2 million, or 21%, an increase at our well site services segment of $97.8 million, or 43%, and an increase at our accommodations segment of $35.7 million, or 13%, partially offset by a decrease in cost of sales at our offshore products segment of $60.6 million, or 16%. Our consolidated gross margin as a percentage of revenues was 22% in both 2010 and 2009.

Our well site services segment cost of sales increased $97.8 million, or 43%, in 2010 compared to 2009 as a result of a $50.5 million, or 30%, increase in rental tools and services cost of sales and a $47.3 million, or 81%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues increased from 25% in 2009 to 32% in 2010. Our rental tools and services gross margin as a percentage of revenues increased from 28% in 2009 to 36% in 2010 primarily due to a more favorable mix of higher value rentals and improved pricing along with improved fixed cost absorption as a result of increased rental tool utilization. Our drilling services gross margin as a percentage of revenues increased from 18% in 2009 to 21% in 2010 primarily due to the increase in drilling activity levels.

Our accommodations segment cost of sales increased $35.7 million, or 13%, in 2010 compared to 2009 primarily as a result of increased activity at our large accommodation facilities supporting oil sands development activities in northern Alberta, Canada, the expansion of two of these facilities and the strengthening of the Canadian dollar versus the U.S. dollar, partially offset by a decrease in third-party accommodations manufacturing and installation costs. Our accommodations segment gross margin as a percentage of revenues was 42% in 2009 and 2010.

Our offshore products segment cost of sales decreased $60.6 million, or 16%, in 2010 compared to 2009 primarily due to a decrease in subsea pipeline and rig and vessel equipment costs. Our offshore products segment gross margin as a percentage of revenues was 26% in both 2009 and 2010.

Tubular services segment cost of sales increased $161.2 million, or 21%, in 2010 compared to 2009 primarily as a result of an increase in tons shipped driven by increased drilling activity, partially offset by lower priced OCTG inventory being sold. Our tubular services segment gross margin as a percentage of revenues decreased from 7% in 2009 to 5% in 2010 primarily due to a larger portion of service related costs expensed on certain program work.

Selling, General and Administrative Expenses.    SG&A expense increased $11.6 million, or 8%, in 2010 compared to 2009 due primarily to an increased accrual for incentive bonuses, increased salaries, wages and benefits and an increase in our accommodations SG&A expenses as a result of the strengthening of the Canadian dollar versus the U.S. dollar. SG&A was 6.3% of revenues in 2010 compared to 6.6% of revenues in 2009.

Depreciation and Amortization.    Depreciation and amortization expense increased $6.1 million, or 5%, in 2010 compared to 2009 due primarily to capital expenditures made during the previous twelve months largely related to our Canadian accommodations business, partially offset by decreased depreciation in our drilling services business where several major assets have become fully-depreciated.

Impairment of Goodwill.    We recorded a goodwill impairment loss of $94.5 million, before tax, in 2009. The impairment was the result of our assessment of several factors affecting our rental tools and services reporting unit. We did not record an impairment of goodwill in 2010.

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Operating Income.    Consolidated operating income increased $136.9 million, or 115%, in 2010 compared to 2009 primarily as a result of the $94.5 million pre-tax goodwill impairment loss recognized in the second quarter of 2009, a $67.6 million increase in operating income from our well site services segment (excluding the goodwill impairment) primarily due to increased U.S. completion activity, the more favorable mix of higher value rentals, improved pricing and increased rental tool utilization in our rental tools and services operation and increased utilization of our rigs in our drilling services business, partially offset by a $20.4 million decrease in operating income from our offshore products segment. Operating income in 2010 included $7.0 million of transaction costs related to the three acquisitions made during the year.

Interest Expense and Interest Income.    Net interest expense increased $0.6 million, or 4%, in 2010 compared to 2009 due to an increase in non-cash interest expense related to the write-off of the remaining balance of debt issuance costs for our prior revolving credit facility, partially offset by reduced average debt levels in 2010. The weighted average interest rate on the Company’s credit facilities was 3.6% in 2010 compared to 1.5% in 2009. Interest income increased as a result of increased cash balances in interest bearing accounts partially offset by the repayment during the first quarter of 2009 of a note receivable from Boots & Coots International Well Control, Inc. (Boots & Coots).

Income Tax Expense.    Our income tax provision for 2010 totaled $72.0 million, or 29.9% of pretax income, compared to $46.1 million, or 43.6% of pretax income, for 2009. The effective tax rate in 2009 was impacted by a significant portion of the goodwill impairment loss recognized during the period being non-deductible for tax purposes. Excluding the goodwill impairment, the effective tax rate for 2009 would have approximated 29.7%.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures, which in the past have included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, replacing and increasing rental tool assets, adding and upgrading drilling rigs, 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 and proceeds from borrowings. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

Cash totaling $215.9 million was provided by operations during the year ended December 31, 2011 compared to cash totaling $230.9 million provided by operations during the year ended December 31, 2010. During 2011, $340.3 million was used to fund working capital, primarily due to increased investments in receivables and inventory in our tubular services and offshore products segments due to higher activity levels. During 2010, $100.0 million was used to fund working capital, primarily due to increased investments in working capital for our tubular services and rental tools and services businesses and lower taxes payable, partially offset by a reduction in accounts receivable at our offshore products segment.

Cash was used in investing activities during the years ended December 31, 2011 and 2010 in the amount of $489.0 million and $889.7 million, respectively. Capital expenditures totaled $487.5 million and $182.2 million during the years ended December 31, 2011 and 2010, respectively. Capital expenditures in both years consisted principally of purchases and installation of assets for our accommodations and well site services segments, and in particular for accommodations investments made in support of Canadian oil sands developments and, in 2011, Australian mining related accommodations facilities.

During the year ended December 31, 2011, we spent cash of $2.2 million to acquire an open camp accommodations facility in Carrizo Springs, Texas to provide accommodations support to customers working in the Eagle Ford Shale basin. This compares to $709.6 million spent, net of cash acquired, during the year ended December 31, 2010 to acquire The MAC Services Group Limited in Sydney, Australia to expand our accommodations business internationally, Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC in Vernal, Utah, an accommodations business servicing the U.S. Rockies and the Bakken Shale region, and Acute Technological Services, Inc. in Houston, Texas, a provider of welding engineering, consulting and services to the energy industry worldwide for both onshore and offshore activities. The Company funded the acquisitions of The MAC and Mountain West with cash on hand and draws under our senior secured credit facilities. We funded the Acute acquisition using cash on hand and our then existing credit facility. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

We currently expect to spend a total of approximately $600 to $700 million for capital expenditures during 2012 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. Approximately 65% of our total estimated 2012 capital expenditures are expected to be spent in our

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accommodations segment. We plan to fund these capital expenditures with cash available, internally generated funds and borrowings under our revolving credit facilities or other corporate borrowings. The foregoing capital expenditure budget does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.

Net cash of $257.9 million was provided by financing activities during the year ended December 31, 2011, primarily as a result of proceeds from the issuance in the second quarter of 2011 of $600 million aggregate principal amount of 6 1/2% Notes, offset by net repayments of outstanding amounts under our revolving credit facilities. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our credit facilities. Net cash of $649.0 million was provided by financing activities during the year ended December 31, 2010, primarily as a result of borrowings under our senior secured credit facilities. We incurred $13.5 million of costs to secure financings in 2011 compared to $24.5 million in 2010.

We believe that cash on hand, cash flow from operations, available borrowings under our credit facilities or other corporate borrowings 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.    On August 27, 2010, the Company announced that its Board of Directors authorized $100 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which expired on December 31, 2009. The Company presently has approximately 51.3 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2012. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. Through December 31, 2011, a total of $12.6 million of our stock (209,300 shares) had been repurchased under this program, leaving a total authorization of up to approximately $87.4 million remaining available under the program.

Credit Facilities.    On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement (Credit Agreement). The Credit Agreement consists of a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The new facilities increased the total commitments available from $500 million under the previous facilities to $1.05 billion. In connection with the execution of the Credit Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $325 million to U.S. $700 million (including $200 million in term loans), and the Total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $175 million to U.S. $350 million (including $100 million in term loans). The maturity date of the Credit Agreement is December 10, 2015. The current principal balance of the term loans is repayable at a rate of 2.5% per quarter of the aggregate principal amount until maturity on December 10, 2015 when the remaining principal is due. We currently have 19 lenders in our Credit Agreement with commitments ranging from $26.6 million to $150 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 facilities, contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0 in 2012 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of these 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, 2011, we were in compliance with our debt covenants and expect to continue to be in compliance during 2012. Borrowings under

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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 2011, our applicable margin over LIBOR ranged from 2.25% to 2.5% and it was 2.25% as of December 31, 2011. Our weighted average interest rate paid under the Credit Agreement was 3.0% during the year ended December 31, 2011 and 3.6% for the year ended December 31, 2010.

As of December 31, 2011, we had $351.9 million outstanding under the Credit Agreement and an additional $25.1 million of outstanding letters of credit, leaving $656.8 million available to be drawn under the facilities.

On July 13, 2011, The MAC entered into a A$150 million Facility Agreement with National Australia Bank Limited. The Facility Agreement amended The MAC’s existing A$75 million revolving loan facility on substantially the same terms, including the maturity date of the Facility Agreement of November 30, 2013. As of December 31, 2011, we had A$42 million outstanding under the Australian facility leaving A$108 million available to be drawn under this facility.

Our total debt represented 37.5% of our combined total debt and shareholders’ equity at December 31, 2011 compared to 35.9% at December 31, 2010.

6 ¹/2% Notes.    On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 ¹/2% senior unsecured notes due 2019 through a private placement to qualified institutional buyers.

The 6 ¹/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 ¹/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 ¹/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 ¹/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 ¹/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:

Twelve Month Period Beginning June 1,	% of Principal Amount
2014		104.875	%
2015		103.250	%
2016		101.625	%
2017		100.000	%

The Company utilized approximately $515 million of the net proceeds of the 6 ¹/2% Note offering in June 2011 to repay borrowings under its senior secured credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.

On June 1, 2011, in connection with the issuance of the 6 ¹/2% Notes, the Company entered into an Indenture (the Indenture), among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company’s ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 ¹/2% Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The Indenture contains customary events of default. As of December 31, 2011, the Company was in compliance with all covenants of the 6 ¹/2% Notes.

Contingent Convertible Notes.    In June 2005, we sold $175 million aggregate principal amount of 2 ³/8% Contingent Convertible Senior Notes (2 ³/8% Notes) due 2025. The 2 ³/8% Notes provide for a net share settlement,

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and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the 2 ³/8% Notes, and common stock of the company, if there is any excess above the principal amount of the 2 ³/8% Notes, at an initial conversion price of $31.75 per share. Shares underlying the 2 ³/8% Notes were included in the calculation of diluted earnings per share during the years 2011 and 2010 because our stock price exceeded the initial conversion price of $31.75. The terms of the 2 ³/8% 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 2 ³/8% Notes are convertible. If a 2 ³/8% Note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of approximately 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. For a more detailed description of our 2 3/8% Notes, please see Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

As of December 31, 2011, we had classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a noncurrent liability based on our ability and intent to refinance the 2 3/8% Notes utilizing borrowings available under our senior secured credit facilities. As of December 31, 2011, the contingent conversion thresholds were met and, as a result, 2 3/8% Note holders could present their notes for conversion during the quarter following the December 31, 2011 measurement date. As of December 31, 2011, the recent trading prices of the 2 3/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. Should a 2 3/8% Note holder convert their notes, we would utilize our existing credit facilities to fund the cash portion of the conversion value.

Contractual Cash Obligations.    The following summarizes our contractual obligations at December 31, 2011 (in thousands):

December 31, 2011	Total		Due in less than 1 year		Due in 1-3 years		Due in 3 - 5 years		Due after 5 years
Contractual obligations:
Total debt, including capital leases (1)	$	1,176,940	$	205,318	$	103,819	$	262,501	$	605,302
Non-cancelable operating leases		47,709		11,821		19,026		8,393		8,469
Purchase obligations		625,567		618,883		6,684		—		—
Total contractual cash obligations	$	1,850,216	$	836,022	$	129,529	$	270,894	$	613,771

(1) Excludes interest on debt. We cannot predict with any certainty the amount of interest due on our revolving debt due to the expected variability of interest rates and principal amounts outstanding. If we assume interest payment amounts are calculated using the outstanding principal balances, interest rates and foreign currency exchange rates as of December 31, 2011 and include applicable commitment fees, estimated interest payments on our credit facilities, 2 3/8% Notes and 6 1/2% Notes would be $58.3 million “due in less than one year,” $105.1 million “due in one to three years,” $88.3 million “due in three to five years” and $94.1 million “due after five years.” In the case of our outstanding term loans, applicable principal pay down amounts have been reflected in the interest payment calculations. See Note 8 the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional for additional information on our credit facilities.

Our debt obligations at December 31, 2011 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 conversion of our 2 3/8% Notes in 2012, the first put/call date for these notes. We have not entered into any material leases subsequent to December 31, 2011.

Effects of Inflation

Our revenues and results of operations have not been materially impacted by inflation in the past three fiscal years.

Off-Balance Sheet Arrangements

As of December 31, 2011, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.

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Tax Matters

Our primary deferred tax assets at December 31, 2011, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, inventory allowance for obsolescence, and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.

Our income tax provision for the year ended December 31, 2011 totaled $131.6 million, or 28.9% of pretax income, compared to $72.0 million, or 29.9% of pretax income, for the year ended December 31, 2010. The decrease in the effective tax rate from the prior year was largely the result of foreign sourced income in 2011 being taxed at lower statutory rates compared to 2010, partially offset by an increase in state taxes.

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

Our Consolidated Financial Statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), which require that management make numerous estimates and assumptions. Actual results could differ from those estimates and assumptions, thus impacting our reported results of operations and financial position. The critical accounting policies and estimates described in this section are those that are most important to the depiction of our financial condition and results of operations and the application of which requires management’s most subjective judgments in making estimates about the effect of matters that are inherently uncertain. We describe our significant accounting policies more fully in Note 2 to Consolidated Financial Statements included in this Annual Report on Form 10-K.

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 obligations and discontinued operations.

Asset Retirement Obligations

We recognize initial estimated asset retirement obligations (ARO) related to properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company derecognizes ARO liabilities when the related obligations are settled. At December 31, 2011, $4.6 million of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities.” The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.

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Tangible and Intangible Assets, including Goodwill

Our goodwill totaled $467.5 million, or 12.6%, of our total assets, as of December 31, 2011. Our other intangible assets totaled $127.6 million, or 3.4%, of our total assets, as of December 31, 2011. 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 losses.

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 rental tools and services, drilling, accommodations, offshore products and tubular services. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full impairment of goodwill at those reporting units as of December 31, 2008. As part of the goodwill impairment analysis, we first perform a qualitative assessment to determine whether it is more likely than not (that is, a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. In performing the two-step impairment test, we estimate the implied fair value (IFV) of each reporting unit 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. 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. 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. In 2011, our qualitative assessment of potential goodwill impairment indicated that it is more likely than not that the fair value of each of our reporting units is greater than its carrying amount and, thus, no trading multiples analyses or discounted projected cash flow calculations were performed and no goodwill impairment was recorded.

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.

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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.

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 the 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 Merton “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 Merton 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

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

In June 2011, the FASB issued amendments to disclosure requirements for the presentation of comprehensive income. This guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other

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comprehensive income, the components of other comprehensive income, and the total of comprehensive income. In December 2011, the FASB issued an amendment deferring the effective date of the requirement to present reclassification adjustments out of accumulated other comprehensive income on the face of the consolidated statement of income. The amendments should be applied retrospectively. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is permitted, because compliance with the amendments is already permitted. The amendments do not require any transition disclosures. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

In September 2011, the FASB issued an accounting standards update which is intended to simplify goodwill impairment testing by giving an entity the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. An entity has the option to bypass such qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The Company early adopted this standard for its annual goodwill impairment tests in 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

ITEM 7A.Quantitative And Qualitative Disclosures About Market Risk

Interest Rate Risk.    We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of December 31, 2011, we had floating rate obligations totaling approximately $394.9 million drawn under our credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate had been 1% higher than December 31, 2011 levels, our consolidated annual interest expense would have increased by a total of approximately $3.9 million.

Foreign Currency Exchange Rate Risk.    Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) 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 in areas outside the U.S. (primarily in our offshore products segment), 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 2011, our realized foreign exchange losses were $1.4 million and are included in “Other operating (income)/expense” in the consolidated statements of income.

Some of our foreign operations are conducted through wholly-owned foreign subsidiaries that have functional currencies other than the U.S. dollar. We currently have subsidiaries whose functional currencies are the Canadian dollar, Australian dollar, the British pound and the Singapore dollar. Assets and liabilities from these subsidiaries are translated into U.S. dollars at the exchange rate in effect at each balance sheet date. The resulting translation gains or losses are reflected as “Accumulated other comprehensive income”  in the “Stockholders’ equity” section of our consolidated balance sheets.

Item 8.     Financial Statements and Supplementary Data

Our Consolidated Financial Statements and supplementary data of the Company appear on pages 65 through 102 of this Annual Report on Form 10-K and are incorporated by reference into this Item 8. Selected quarterly financial data is set forth in Note 16 to our Consolidated Financial Statements, which is incorporated herein by reference.

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Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

There were no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent auditors during our two most recent fiscal years or any subsequent interim period.

Item 9A.    Controls and Procedures

(i) Evaluation of Disclosure Controls and Procedures

Evaluation of Disclosure Controls and Procedures.    As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of 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 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, 2011 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 Commission. These certifications accompanied this report when filed with the Commission, but are not set forth herein.

(ii) Internal Control Over Financial Reporting

(a)     Management’s annual report on internal control over financial reporting.

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, 2011 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–Integrated Framework. Based on our assessment we believe that, as of December 31, 2011, the Company’s internal control over financial reporting is effective based on those criteria.

56

(b) Attestation report of the registered public accounting firm.

The attestation report of Ernst & Young LLP, the Company’s independent registered public accounting firm, on the Company’s internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 67 and is incorporated herein by reference.

(c) Changes in internal control over financial reporting.

During the Company’s fourth fiscal quarter ended December 31, 2011, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B.    Other Information

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2011 that was not reported on a Form 8-K during such time.

PARTIII

Item 10.    Director, Executive Officers and Corporate Governance

(1) Information concerning directors, including the Company’s audit committee financial expert, appears in the Company’s Definitive Proxy Statement for the 2012 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 2012 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 2012 Annual Meeting of Stockholders, under “Section 16(a) Beneficial Ownership Reporting Compliance.” This portion of the Definitive Proxy Statement is incorporated herein by reference.

Item 11.    Executive Compensation

The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

The information required by Item 13 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders.

Item 14.    Principal Accountant Fees and Services

Information concerning principal accountant fees and services and the audit committee’s preapproval policies and procedures appear in the Company’s Definitive Proxy Statement for the 2012 Annual Meeting of Stockholders under the heading “Fees Paid to Ernst & Young LLP” and is incorporated herein by reference.

57

PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1)Financial Statements: Reference is made to the index set forth on page 65 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 of Regulation S-K.

(b) Index of Exhibits

Exhibit No.		Description
2.1	—	Scheme Implementation Deed, dated October 15, 2010, by and between Oil States International, Inc. and The MAC Services Group Limited (incorporated by reference to Exhibit 2.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 15, 2010 (File No. 001-16337)).
3.1	—	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
3.2	—	Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).
3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1, as filed with the Commission on November 7, 2000 (File No. 333-43400)).
4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003 (File No. 001-16337)).
4.4	—	Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.4 to Oil States’ Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).
4.5	—	Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Oil States’ Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).

58

Exhibit No.		Description
4.6	—	Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 to Oil States’ Current Reports on Form 8-K as filed with the Commission on June 23, 2005 and July 13, 2005 (File No. 001-16337)).
4.7	—	Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).
4.8	—	Supplemental Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).
10.1	—	Combination Agreement dated as of July 31, 2000 by and among Oil States International, Inc., HWC Energy Services, Inc., Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI Group Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-1, as filed with the Commission on August 10, 2000 (File No. 333-43400)).
10.2	—	Plan of Arrangement of PTI Group Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.3	—	Support Agreement between Oil States International, Inc. and PTI Holdco (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.4	—	Voting and Exchange Trust Agreement by and among Oil States International, Inc., PTI Holdco and Montreal Trust Company of Canada (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.5**	—	Second Amended and Restated 2001 Equity Participation Plan effective March 30, 2009 (incorporated by reference to Exhibit 10.5 to Oil States’ Current Report on Form 8-K, as filed with the Commission on April 2, 2009 (File No. 001-16337)).
10.6**	—	Deferred Compensation Plan effective November 1, 2003 (incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, as filed with the Commission on March 5, 2004 (File No. 001-16337)).
10.7**	—	Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.8**	—	Executive Agreement between Oil States International, Inc. and Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.9**	—	Form of Change of Control Severance Plan for Selected Members of Management (incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1, as filed with the Commission on December 12, 2000 (File No. 333-43400)).
10.10	—	Credit Agreement, dated as of October 30, 2003, among Oil States International, Inc., the Lenders named therein and Wells Fargo Bank Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2003, as filed with the Commission on November 12, 2003 (File No. 001-16337)).

59

Exhibit No.		Description
10.10A	—	Incremental Assumption Agreement, dated as of May 10, 2004, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12A to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2004, as filed with the Commission on August 4, 2004 (File No. 001-16337)).
10.10B	—	Amendment No. 1, dated as of January 31, 2005, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12B to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.10C	—	Amendment No. 2, dated as of December 5, 2006, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12C to the Company’s Current Report on Form 8-K, as filed with the Commission on December 8, 2006 (File No. 001-16337)).
10.10D	—	Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company’s Current Report on Form 8-K, as filed with the Commission on December 18, 2007 (File No. 001-16337)).
10.10E	—	Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company’s Current Report on Form 8-K, as filed with the Commission on October 2, 2009 (File No. 001-16337)).
10.10F	—	Amended and Restated Credit Agreement, dated as of December 10, 2010, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., as borrowers, the lenders named therein and Wells Fargo Bank, N.A., as Administrative Agent, U.S. Collateral Agent, the U.S. Swing Line Lender and an Issuing Bank; and Royal Bank of Canada, as Canadian Administrative Agent, Canadian Collateral Agent and the Canadian Swing Line Lender; JP Morgan Chase Bank, N.A., as Syndication Agent and Wells Fargo Securities, LLC, RBC Capital Markets and JP Morgan Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on December 20, 2010 (File No. 001-16337)).
10.10G	—	Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).
10.11**	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004 (File No. 001-16337)).
10.12**	—	Form of Director Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

60

Exhibit No.		Description
10.13**	—	Form of Employee Non Qualified Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.14**	—	Form of Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.15**	—	Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company’s Report on Form 8-K as filed with the Commission on November 15, 2006 (File No. 001-16337)).
10.16**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005 (File No. 001-16337)).
10.17**	—	Form of Non-Employee Director Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.22 to the Company’s Report of Form 8-K, as filed with the Commission on May 24, 2005 (File No. 001-16337)).
10.18**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Bradley Dodson) effective October 10, 2006 (incorporated by reference to Exhibit 10.24 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, as filed with the Commission on November 3, 2006 (File No. 001-16337)).
10.19**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007 (incorporated by reference to Exhibit 10.25 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, as filed with the Commission on August 2, 2007 (File No. 001-16337)).
10.20**	—	Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009 (incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.21**	—	Amendment to the Executive Agreement of Bradley Dodson, effective January 1, 2009 (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.22**	—	Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009 (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.23**	—	Amendment to the Executive Agreement of Ron Green, effective January 1, 2009 (incorporated by reference to Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.24**	—	Amendment to the Executive Agreement of Robert Hampton, effective January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

61

Exhibit No.		Description
10.25**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Charles Moses), effective March 4, 2010 (incorporated by reference to Exhibit 10.26 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, as filed with the Commission on April 30, 2010 (File No. 001-16337)).
10.26**	—	Call Option Agreement, dated October 15, 2010, by and between Marley Holdings Pty Limited and PTI Holding Company 2 Pty Limited (incorporated by reference to Exhibit 10.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 5, 2010 (File No. 001-16337)).
10.27**	—	Assignment Letter between the Company and Ron Green effective May 3, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 6, 2011 (File No. 001-16337)).
21.1*	—	List of subsidiaries of the Company.
23.1*	—	Consent of Independent Registered Public Accounting Firm.
24.1*	—	Powers of Attorney for Directors.
31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
32.1***	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
32.2***	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
101.INS***	—	XBRL Instance Document
101.SCH***	—	XBRL Taxonomy Extension Schema Document
101.CAL***	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB***	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	—	XBRL Taxonomy Extension Presentation Linkbase Document

    * Filed herewith

  ** Management contracts or compensatory plans or arrangements

*** Furnished herewith.

62

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 17, 2012.

OIL STATES INTERNATIONAL, INC.
By	/s/     CINDY B. TAYLOR
	Cindy B. Taylor      President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 17, 2012.

Signature	Title
/s/     STEPHEN A. WELLS* Stephen A. Wells	Chairman of the Board
/s/     CINDY B. TAYLOR Cindy B. Taylor	Director, President & Chief Executive Officer (Principal Executive Officer)
/s/     BRADLEY J. DODSON Bradley J. Dodson	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/     ROBERT W. HAMPTON Robert W. Hampton	Senior Vice President — Accounting and Corporate Secretary (Principal Accounting Officer)
/s/     MARTIN A. LAMBERT* Martin A. Lambert	Director
/s/     S. JAMES NELSON, JR.* S. James Nelson, Jr.	Director
/s/     MARK G. PAPA* Mark G. Papa	Director
/s/     GARY L. ROSENTHAL* Gary L. Rosenthal	Director
/s/     CHRISTOPHER T. SEAVER* Christopher T. Seaver	Director
/s/     DOUGLAS E. SWANSON* Douglas E. Swanson	Director
/s/     WILLIAM T. VAN KLEEF* William T. Van Kleef	Director

*By:	/s/     BRADLEY J. DODSON
	Bradley J. Dodson, pursuant to a power of attorney filed as Exhibit 24.1 to this Annual Report on Form 10-K

63

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

INDEX TO

CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	65
Report of Independent Registered Public Accounting Firm on the Company’s Internal Control Over Financial Reporting	66
Consolidated Statements of Income for the Years Ended December 31, 2011, 2010, and 2009	67
Consolidated Balance Sheets at December 31, 2011 and 2010	68
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2011, 2010 and 2009	69
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010, and 2009	70
Notes to Consolidated Financial Statements	71–104

64

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Oil States International, Inc.:

We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oil States International, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 17, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 17, 2012

65

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Oil States International, Inc.:

We have audited Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Oil States International, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Oil States International, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 17, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 17, 2012

66

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2011			2010			2009
	(In Thousands, Except Per Share Amounts)
Revenues:
Product	$	1,815,526		$	1,282,212		$	1,279,181
Service and other		1,663,654			1,129,772			829,069
		3,479,180			2,411,984			2,108,250
Costs and expenses:
Product costs		1,617,399			1,147,427			1,109,769
Service and other costs		981,868			726,867			530,429
Selling, general and administrative expenses		182,434			150,865			139,293
Depreciation and amortization expense		188,147			124,202			118,108
Impairment of goodwill		—			—			94,528
Other operating (income) / expense		1,809			7,041			(2,606	)
		2,971,657			2,156,402			1,989,521
Operating income		507,523			255,582			118,729
Interest expense, net of capitalized interest		(57,506	)		(16,274	)		(15,266	)
Interest income		1,700			751			380
Equity in earnings (loss) of unconsolidated affiliates		(163	)		239			1,452
Other income		3,515			330			414
Income before income taxes		455,069			240,628			105,709
Income tax provision		(131,647	)		(72,023	)		(46,097	)
Net income	$	323,422		$	168,605		$	59,612
Less: Net income attributable to noncontrolling interests		969			587			498
Net income attributable to Oil States International, Inc.	$	322,453		$	168,018		$	59,114
Net income per share attributable to Oil States International, Inc. common stockholders
Basic	$	6.30		$	3.34		$	1.19
Diluted	$	5.86		$	3.19		$	1.18
Weighted average number of common shares outstanding (in thousands):
Basic		51,163			50,238			49,625
Diluted		55,007			52,700			50,219

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(In Thousands, Except Share Amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	71,721		$	96,350
Accounts receivable, net		732,240			478,739
Inventories, net		653,698			501,435
Prepaid expenses and other current assets		32,000			23,480
Total current assets		1,489,659			1,100,004
Property, plant and equipment, net		1,557,088			1,252,657
Goodwill, net		467,450			475,222
Other intangible assets, net		127,602			139,421
Other noncurrent assets		61,842			48,695
Total assets	$	3,703,641		$	3,015,999
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	348,957		$	304,739
Income taxes		10,395			4,604
Current portion of long-term debt and capitalized leases		34,435			181,175
Deferred revenue		75,497			60,847
Other current liabilities		5,665			2,810
Total current liabilities		474,949			554,175
Long-term debt and capitalized leases		1,142,505			731,732
Deferred income taxes		97,377			81,198
Other noncurrent liabilities		25,538			19,961
Total liabilities		1,740,369			1,387,066
Stockholders’ equity:
Oil States International, Inc. stockholders’ equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 54,803,539 shares and 54,108,011 shares issued, respectively, and 51,288,750 shares and 50,838,863 shares outstanding, respectively		548			541
Additional paid-in capital		545,730			508,429
Retained earnings		1,450,586			1,128,133
Accumulated other comprehensive income		74,371			84,549
Common stock held in treasury at cost, 3,514,789 and 3,269,148 shares, respectively		(109,079	)		(93,746	)
Total Oil States International, Inc. stockholders’ equity		1,962,156			1,627,906
Noncontrolling interest		1,116			1,027
Total stockholders’ equity		1,963,272			1,628,933
Total liabilities and stockholders’ equity	$	3,703,641		$	3,015,999

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

		Common Stock			Additional Paid-In Capital			Retained Earnings		Comprehensive Income			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Noncontrolling Interest
		(In thousands)
Balance, December 31, 2008		$	526		$	453,733		$	901,001				$	(28,409	)	$	(91,831	)	$	521
Net income									59,114	$	59,114									498
Currency translation adjustment											72,548			72,548						199
Other comprehensive loss											(24	)		(24	)
Comprehensive income										$	131,638
Exercise of stock options, including tax benefit			2			3,146
Amortization of restricted stock compensation						6,008
Surrender of stock to pay taxes on restricted stock awards			3			(3	)										(511	)
Stock option expense						5,542
Other						2											1
Balance, December 31, 2009		$	531		$	468,428		$	960,115				$	44,115		$	(92,341	)	$	1,218
Net income									168,018	$	168,018									587
Currency translation adjustment											40,274			40,274						25
Other comprehensive income											160			160
Comprehensive income										$	208,452
Dividends paid																				(803	)
Exercise of stock options, including tax benefit			9			27,380
Amortization of restricted stock compensation						6,592
Surrender of stock to pay taxes on restricted stock awards			2			(2	)										(1,406	)
Stock option expense	��					6,028
Other			(1	)		3											1
Balance, December 31, 2010		$	541		$	508,429		$	1,128,133				$	84,549		$	(93,746	)	$	1,027
Net income									322,453	$	322,453									969
Currency translation adjustment											(10,079	)		(10,079	)					(21	)
Other comprehensive loss											(99	)		(99	)
Comprehensive income										$	312,275
Dividends paid																				(859	)
Exercise of stock options, including tax benefit			5			22,732
Amortization of restricted stock compensation						8,412
Surrender of stock to pay taxes on restricted stock awards			2			(2	)										(2,702	)
Stock option expense						6,153
Stock acquired for cash																	(12,632	)
Other						6											1
Balance, December 31, 2011		$	548		$	545,730		$	1,450,586				$	74,371		$	(109,079	)	$	1,116

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(In Thousands)
Cash flows from operating activities:
Net income	$	323,422		$	168,605		$	59,612
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		188,147			124,202			118,108
Deferred income tax provision (benefit)		27,075			20,590			(15,126	)
Excess tax benefits from share-based payment arrangements		(8,583	)		(4,029	)		—
Loss on impairment of goodwill		—			—			94,528
Non-cash compensation charge		14,565			12,620			11,550
Accretion of debt discount		7,786			7,249			6,749
Amortization of deferred financing costs		6,497			1,703			1,053
Other, net		(2,654	)		(52	)		863
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		(260,186	)		(61,835	)		205,627
Inventories		(154,290	)		(75,416	)		200,469
Accounts payable and accrued liabilities		47,610			82,032			(168,758	)
Taxes payable		24,789			(22,468	)		(38,428	)
Other current assets and liabilities, net		1,735			(22,279	)		(22,885	)
Net cash flows provided by operating activities		215,913			230,922			453,362
Cash flows from investing activities:
Capital expenditures, including capitalized interest		(487,482	)		(182,207	)		(124,488	)
Acquisitions of businesses, net of cash acquired		(2,412	)		(709,575	)		18
Proceeds from sale of investment and collection of notes receivable		—			—			21,166
Proceeds from sale of buildings and equipment		5,949			2,734			2,839
Other, net		(5,010	)		(632	)		(2,143	)
Net cash flows used in investing activities		(488,955	)		(889,680	)		(102,608	)
Cash flows from financing activities:
Revolving credit borrowings and (repayments), net		(316,736	)		347,129			(294,760	)
6 1/2% senior notes issued		600,000			—			—
Term loan borrowings (repayments)		(14,972	)		300,955			—
Debt and capital lease repayments		(2,529	)		(487	)		(4,961	)
Issuance of common stock from share based payment arrangements		14,154			23,361			3,460
Purchase of treasury stock		(12,632	)		—			—
Excess tax benefits from share based payment arrangements		8,583			4,029			—
Payment of financing costs		(13,464	)		(24,548	)		—
Other, net		(4,516	)		(1,407	)		(512	)
Net cash flows provided by (used in) financing activities		257,888			649,032			(296,773	)
Effect of exchange rate changes on cash		(9,332	)		16,477			5,695
Net increase (decrease) in cash and cash equivalents from continuing operations continuing operations		(24,486	)		6,751			59,676
Net cash used in discontinued operations – operating activities		(143	)		(143	)		(133	)
Cash and cash equivalents, beginning of year		96,350			89,742			30,199
Cash and cash equivalents, end of year	$	71,721		$	96,350		$	89,742

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Basis of Presentation

The Consolidated Financial Statements include the accounts of Oil States International, Inc. (Oil States or the Company) and its consolidated subsidiaries. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. The Company’s operations prior to 2001 were conducted by Oil States Industries, Inc. (OSI). In February 2001, the Company acquired three companies (Oil States Energy Services, Inc. (OSES) (formerly known as HWC Energy Services, Inc.); PTI Group, Inc. (PTI) and Sooner Inc. (Sooner)) and completed its initial public offering. All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying Consolidated Financial Statements.

The Company, through its subsidiaries, is a leading provider of specialty products and services to oil and gas drilling and production companies throughout the world. Through its accommodations business, the Company also serves other natural resource markets, principally in Australia. It operates in a substantial number of the world’s active oil and gas producing regions, including the Gulf of Mexico, U.S. onshore, Canada, Australia, the North Sea, Southeast Asia, South America, West Africa and India. The Company operates in four principal business segments — accommodations, offshore products, well site services and tubular services.

2.    Summary of Significant Accounting Policies

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, and debt instruments. The Company believes that the carrying values of these instruments, other than our 2 3/8% Notes and our 6 1/2% Notes, on the accompanying consolidated balance sheets approximate their fair values.

The fair values of our 2 3/8% and 6 1/2 % Notes are estimated based on quoted prices in active markets (Level 1 fair value measurements). The carrying amounts and fair values of these notes were as follows (in thousands):

				December 31, 2011				December 31, 2010
	Interest Rate			Carrying Value		Fair Value		Carrying Value		Fair Value
6 1/2% Notes
Principal amount due 2019		6 1/2	%	$	600,000	$	625,128	$	—	$	—
2 3/8% Notes
Principal amount due 2025		2 3/8	%	$	174,990	$	411,396	$	175,000	$	354,057
Less: unamortized discount					4,106		—		11,892		—
Net value				$	170,884	$	411,396	$	163,108	$	354,057

As of December 31, 2011, the estimated fair value of the Company’s debt outstanding under its credit facilities was estimated to be at fair value.

As of December 31, 2011, the Company had approximately $71.7 million of cash and cash equivalents and $656.8 million of the Company’s U.S. and Canadian revolving credit facilities available for future financing needs. The Company also had availability totaling A$108 million under its Australian credit facility. As of December 31, 2011, we had $27.4 million of outstanding letters of credit.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Inventories

Inventories consist of tubular and other oilfield products, manufactured equipment, spare parts for manufactured equipment, raw materials and supplies and materials for the construction of remote accommodation facilities. Inventories include raw materials, labor, subcontractor charges and manufacturing overhead and are carried at the lower of cost or market. The cost of inventories is determined on an average cost or specific-identification method.

Property, Plant, and Equipment

Property, plant, and equipment are stated at cost or at estimated fair market value at acquisition date if acquired in a business combination, and depreciation is computed, for assets owned or recorded under capital lease, using the straight-line method, after allowing for salvage value where applicable, over the estimated useful lives of the assets. We use the component depreciation method for our drilling services and Australian accommodations assets. Leasehold improvements are capitalized and amortized over the lesser of the life of the lease or the estimated useful life of the asset.

Expenditures for repairs and maintenance are charged to expense when incurred. Expenditures for major renewals and betterments, which extend the useful lives of existing equipment, are capitalized and depreciated. Upon retirement or disposition of property and equipment, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in the statements of income.

Asset Retirement Obligations

We recognize initial estimated asset retirement obligations (ARO) related to properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company relieves ARO liabilities when the related obligations are settled. At December 31, 2011, $4.6 million of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities”. The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price paid for acquired businesses over the allocated fair value of the related net assets after impairments, if applicable. Goodwill is stated net of accumulated amortization of $11 million as of December 31, 2011 and 2010.

We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. Our reporting units with goodwill remaining include accommodations, offshore products and rental tools and services. During 2008 and 2009, 100% of the goodwill associated with our tubular services and drilling reporting units was impaired as discussed in Note 7 to these Consolidated Financial Statements. Impairment of goodwill is tested at the reporting unit level by first performing a qualitative assessment to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. In performing the two-step impairment test, we compare the reporting unit’s carrying amount, including goodwill, to the implied fair value (IFV) of the reporting unit. The IFV of the reporting units are estimated using an analysis of trading multiples of comparable companies to our reporting units. We also utilize discounted projected cash flows and acquisition multiples analyses in certain circumstances. We discount our projected cash flows using a long-term weighted average cost of capital for each reporting unit based on our estimate of investment returns that would be required by a market participant. If the carrying amount of the reporting unit exceeds its fair value, goodwill is considered impaired, and a second step is performed to determine the amount of impairment, if any. We conduct our annual impairment test in December of each year.

For intangible assets that we amortize, we review the useful life of the intangible asset and evaluate each reporting period whether events and circumstances warrant a revision to the remaining useful life. We evaluate the remaining useful life of an intangible asset that is not being amortized each reporting period to determine whether events and circumstances continue to support an indefinite useful life.

See Note 7 — Goodwill and Other Intangible Assets.

Impairment of Long-Lived Assets

In compliance with current accounting standards regarding the accounting for the impairment or disposal of long-lived assets at the asset group level, the recoverability of the carrying values of long-lived assets, including intangible assets, is assessed at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying value of such asset groups may not be recoverable based on estimated future cash flows. If this assessment indicates that the carrying values will not be recoverable, as determined based on undiscounted cash flows over the remaining useful lives, an impairment loss is recognized. The impairment loss equals the excess of the carrying value over the fair value of the asset. The fair value of the asset is based on prices of similar assets, if available, or discounted cash flows. Based on the Company’s review, the carrying values of its asset groups are recoverable, and no impairment losses have been recorded for the periods presented.

Foreign Currency and Other Comprehensive Income

Gains and losses resulting from balance sheet translation of foreign operations where a foreign currency is the functional currency are included as a separate component of accumulated other comprehensive income within stockholders’ equity representing substantially all of the balances within accumulated other comprehensive income. Remeasurements of intercompany loans denominated in a different currency than the functional currency of the entity that are of a long-term investment nature are recognized as other comprehensive income within stockholders’ equity. Gains and losses resulting from balance sheet remeasurements of assets and liabilities denominated in a different currency than the functional currency, other than intercompany loans that are of a long-term investment nature, are included in the consolidated statements of income as incurred.

Foreign Exchange Risk

A portion of revenues, earnings and net investments in foreign affiliates are exposed to changes in foreign exchange rates. We seek to manage our foreign exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. Foreign exchange risk is also managed through foreign currency denominated debt. The Company had no foreign currency exchange contracts outstanding at December 31, 2011 or December 31, 2010. Net gains or losses from foreign currency exchange contracts that are designated as

73

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

hedges would be recognized in the income statement to offset realized foreign currency gain or loss on the underlying transaction. Foreign exchange gains and losses associated with our operations have totaled a $1.4 million loss in 2011, a $1.1 million loss in 2010 and a $0.3 million loss in 2009 and were included in “Other operating (income)/expense.”

Interest Capitalization

Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. For the years ended December 31, 2011, 2010, and 2009, $5.3 million, $0.2 million and $0.1 million were capitalized, respectively.

Revenue and Cost Recognition

Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. In our accommodations and well site services segments, revenues are recognized based on a periodic (usually daily) rental or room rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.

Cost of goods sold includes all direct material and labor costs and those costs related to contract performance, such as indirect labor, supplies, tools and repairs. Selling, general, and administrative costs are charged to expense as incurred.

Income Taxes

The Company follows the liability method of accounting for income taxes in accordance with current accounting standards regarding the accounting for income taxes. Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets or liabilities are recovered or settled.

When the Company’s earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries.

In accordance with current accounting standards, the Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. Management will continue to evaluate the appropriateness of the valuation allowance in the future based upon the operating results of the Company.

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.

Receivables and Concentration of Credit Risk, Concentration of Suppliers

Based on the nature of its customer base, the Company does not believe that it has any significant concentrations of credit risk other than its concentration in the oil and gas industry. The Company evaluates the credit-worthiness of its significant, new and existing customers’ financial condition and, generally, the Company does not require significant collateral from its customers.

The Company purchased 85% of its oilfield tubular goods from three suppliers in 2011, with the largest supplier representing 58% of its purchases in the period. The loss of any significant supplier in the tubular services segment could materially adversely affect it.

Allowances for Doubtful Accounts

The Company maintains allowances for doubtful accounts for estimated losses resulting from the inability of the Company’s customers to make required payments. If a trade receivable is deemed to be uncollectible, such receivable is charged-off against the allowance for doubtful accounts. The Company considers the following factors when determining if collection of revenue is reasonably assured: customer credit-worthiness, past transaction history with the customer, current economic industry trends, customer solvency and changes in customer payment terms. If the Company has no previous experience with the customer, the Company typically obtains reports from various credit organizations to ensure that the customer has a history of paying its creditors. The Company may also request financial information, including financial statements or other documents to ensure that the customer has the means of making payment. If these factors do not indicate collection is reasonably assured, the Company would require a prepayment or other arrangement to support revenue recognition and recording of a trade receivable. If the financial condition of the Company’s customers were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.

Earnings per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of common shares outstanding, including 1,757 shares of common stock as of December 31, 2010, issuable upon exercise of exchangeable shares of one of the Company’s Canadian subsidiaries. These exchangeable shares, which were issued to certain former shareholders of PTI Group Inc. in connection with the Company’s IPO and the combination of PTI into the Company, are intended to have characteristics essentially equivalent to the Company’s common stock prior to the exchange. We have treated the shares of common stock issuable upon exchange of the exchangeable shares as outstanding. There were no exchangeable shares outstanding as of December 31, 2011. All shares of restricted stock awarded under the Company’s Equity Participation Plan are included in the Company’s basic shares when they vest and fully diluted shares when such restricted stock shares are awarded.

Diluted EPS amounts include the effect of the Company’s outstanding stock options and restricted stock shares under the treasury stock method. In addition, shares assumed to be issued upon conversion of the Company’s 2 3/8% Notes averaged 3,023,420, 1,647,321 and 202,820 during the years ended December 31, 2011, December 31, 2010 and December 31, 2009, respectively, and are included in the calculation of fully diluted shares outstanding and fully diluted earnings per share.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Stock-Based Compensation

Current accounting standards regarding share-based payments require companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. During the years ended December 31, 2011, 2010 and 2009, the Company recognized non-cash general and administrative expenses for stock options and restricted stock awards totaling $14.6 million, $12.6 million and $11.5 million, respectively. The Company accounts for assets held in a Rabbi Trust for certain participants under the Company’s deferred compensation plan in accordance with current accounting standards. See Note 13.

Guarantees

The Company applies current accounting standards regarding guarantor’s accounting and disclosure requirements for guarantees, including indirect indebtedness of others, for the Company’s obligations under certain guarantees.

Pursuant to these standards, the Company is required to disclose the changes in product warranty liabilities. Some of our products in our offshore products and accommodations businesses are sold with a warranty, generally ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are estimated based upon historical experience by product, configuration and geographic region.

Changes in the warranty liabilities were as follows (in thousands):

	Year Ended December 31,
	2011			2010
Beginning balance	$	1,576		$	2,169
Provision for warranties issued		1,738			1,314
Settlements made		(1,488	)		(1,924	)
Translation and other changes		(72	)		17
Ending balance	$	1,754		$	1,576

Current warranty provisions are typically related to the current year’s sales, while warranty settlements are associated with payments to service the warranty obligations.

During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2011, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements (letters of credit) was approximately $27.4 million. The Company has not recorded any liability in connection with these guarantee arrangements beyond that required to appropriately account for the underlying transaction being guaranteed. The Company does not believe, based on historical experience and information currently available, that it is likely that any amounts will be required to be paid under these guarantee arrangements.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Examples of a few such estimates include potential future adjustments as a result of contractual agreements, revenue and income recognized on the percentage-of-completion method, estimates of the amount and timing of costs to be incurred for asset retirement obligations, the valuation allowance recorded on net deferred tax assets, warranty, inventory and allowance for doubtful accounts. Actual results could materially differ from those estimates.

Discontinued Operations

Prior to our initial public offering in February 2001, we sold businesses and reported the operating results of those businesses as discontinued operations. Existing liabilities related to the discontinued operations as of December 31, 2011 and 2010 represent an estimate of the remaining contingent liabilities associated with the Company’s exit from those businesses.

Subsequent Events

In accordance with authoritative guidance, the Company evaluates all events and transactions that occur after the balance sheet date, but before financial statements are issued for possible recognition or disclosure.

3.    Details of Selected Balance Sheet Accounts

Additional information regarding selected balance sheet accounts at December 31, 2011 and 2010 is presented below (in thousands):

	2011			2010
Accounts receivable, net:
Trade	$	553,481		$	365,988
Unbilled revenue		180,273			113,389
Other		2,449			3,462
Total accounts receivable		736,203			482,839
Allowance for doubtful accounts		(3,963	)		(4,100	)
	$	732,240		$	478,739

	2011			2010
Inventories, net:
Tubular goods	$	420,519		$	332,720
Other finished goods and purchased products		80,184			71,266
Work in process		76,353			45,662
Raw materials		86,672			60,241
Total inventories		663,728			509,889
Allowance for obsolescence		(10,030	)		(8,454	)
	$	653,698		$	501,435

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Estimated Useful  Life		2011			2010
Property, plant and equipment, net:
Land			$	48,989		$	43,411
Buildings and leasehold improvements		1-40 years		208,918			193,617
Machinery and equipment		1-29 years		351,130			311,217
Accommodations assets		2-15 years		1,105,969			840,002
Rental tools		4-10 years		203,759			166,245
Office furniture and equipment		1-10 years		48,081			36,325
Vehicles		2-10 years		100,554			82,783
Construction in progress				166,371			113,773
Total property, plant and equipment				2,233,771			1,787,373
Accumulated depreciation				(676,683	)		(534,716	)
			$	1,557,088		$	1,252,657

Depreciation expense was $174.9 million, $121.6 million and $114.7 million in the years ended December 31, 2011, 2010 and 2009, respectively.

	2011		2010
Accounts payable and accrued liabilities:
Trade accounts payable	$	252,209	$	224,543
Accrued compensation		61,394		47,760
Accrued interest		6,035		2,772
Insurance liabilities		12,396		8,615
Accrued taxes, other than income taxes		5,889		4,887
Liabilities related to discontinued operations		2,125		2,268
Other		8,909		13,894
	$	348,957	$	304,739

4.    Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

In June 2011, the FASB issued amendments to disclosure requirements for the presentation of comprehensive income. This guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments should be applied retrospectively. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption is permitted, because compliance with the amendments is already permitted. The amendments do not require any transition

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disclosures. In December 2011, the FASB issued an amendment deferring the effective date of the requirement to present reclassification adjustments out of accumulated other comprehensive income on the face of the consolidated statement of income. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

In September 2011, the FASB issued an accounting standards update which is intended to simplify goodwill impairment testing by giving an entity the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. An entity has the option to bypass such qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. The Company early adopted this standard for its annual goodwill impairment tests in 2011. The adoption of this standard did not have a material effect on our consolidated financial statements.

5.    Acquisitions and Supplemental Cash Flow Information

Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2011, 2010 and 2009 are summarized as follows (in thousands):

	2011			2010			2009
Fair value of assets acquired including intangibles and goodwill	$	(8,880	)	$	850,557		$	3,112
Liabilities assumed		11,292			(119,386	)		(411	)
Noncash consideration		—			(7,966	)		(379	)
Cash acquired		—			(13,630	)		(2,340	)
Cash used in acquisition of businesses	$	2,412		$	709,575		$	(18	)

2011

On November 1, 2011, we purchased an open camp accommodations facility located in Carrizo Springs, Texas for total consideration of $2.2 million. This facility will provide accommodations support to customers working in the Eagle Ford Shale oil and gas basin in Texas. The operations of the Carrizo Springs facility have been included in our accommodations segment since the date of acquisition.

2010

On December 30, 2010, we acquired all of the ordinary shares of The MAC Services Group Limited (The MAC), through a Scheme of Arrangement (the Scheme) under the Corporations Act of Australia. The MAC is headquartered in Sydney, Australia and supplies accommodations services to the Australian natural resources market. Under the terms of the Scheme, each shareholder of The MAC received $3.95 (A$3.90) per share in cash. The total purchase price was $638 million, net of cash acquired plus debt assumed of $87 million. The MAC’s operations have been included as part of our accommodations segment beginning in 2011.

The following unaudited pro forma supplemental financial information presents the consolidated results of operations of the Company and The MAC as if the acquisition of The MAC had occurred on January 1, 2009. The Company has adjusted historical financial information to give effect to pro forma items that are directly

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

attributable to the acquisition and expected to have a continuing impact on the consolidated results. These items include adjustments to record the incremental amortization and depreciation expense related to the increase in fair values of the acquired assets, interest expense related to borrowings under the Company’s senior credit facilities to fund the acquisition and to reclassify certain items to conform to the Company’s financial reporting presentation. The unaudited pro forma does not purport to be indicative of the results of operations had the transaction occurred on the date indicated or of future results for the combined entities (in thousands, except per share data):

	Year Ended December 31,
	2010		2009
	(Unaudited)
Revenues	$	2,526,677	$	2,203,124
Net income attributable to Oil States International, Inc.		163,529		55,736
Net income per share attributable to Oil States International, Inc common stockholders
Basic	$	3.26	$	1.12
Diluted	$	3.10	$	1.11

Included in the pro forma results above for the years ended December 31, 2010 and 2009 are (1) depreciation of the increased fair value of property, plant and equipment acquired as part of The MAC, totaling $8.6 million and $7.4 million, respectively, net of tax, or $0.16 and $0.15, respectively, per diluted share, (2) amortization expense for intangibles acquired as part of the purchase of The MAC, totaling $6.0 million and $5.2 million, respectively, net of tax, or $0.11 and $0.10, respectively, per diluted share and, (3) interest expense of $10.8 million and $11.0 million, respectively, net of tax, or $0.20 and $0.22, respectively, per diluted share. The year ended December 31, 2010 pro forma results also include The MAC acquisition costs of approximately $12.5 million ($4.6 million recorded on the Company’s books and $7.9 million recorded on The MAC’s books), net of tax, or $0.24 per diluted share.

On December 20, 2010, we also acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million and estimated contingent consideration of $3.6 million. Headquartered in Vernal, Utah, with operations in the Rockies and the Bakken Shale region, Mountain West provides remote site workforce accommodations to the oil and gas industry. Mountain West has been included in the accommodations segment since its date of acquisition.

The Company funded the acquisitions of The MAC and Mountain West with cash on hand and draws under our senior secured credit facilities. See Note 8 for additional information on our senior secured bank facilities.

On October 5, 2010, we purchased all of the equity of Acute Technological Services, Inc. (Acute) for total consideration of $30.2 million. Headquartered in Houston, Texas with additional operations in Brazil, Acute provides metallurgical and welding engineering, consulting and services to the oil and gas industry in support of critical, complex subsea component manufacturing and deepwater riser fabrication on a global basis. Acute has been included in the offshore products segment since its date of acquisition. The Company funded the Acute acquisition using cash on hand and our then existing credit facility.

The acquisitions of Acute and Mountain West were not material to the Company’s Consolidated Financial Statements, and, therefore, the Company does not present pro forma information for these acquisitions.

2009

In June 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 segment since the date of acquisition.

Supplemental Cash Flow Information

Cash paid during the years ended December 31, 2011, 2010 and 2009 for interest and income taxes was as follows (in thousands):

	2011		2010		2009
Interest (net of amounts capitalized)	$	44,332	$	7,303	$	7,549
Income taxes, net of refunds	$	79,190	$	75,303	$	102,759
Non-cash investing activities:
Assets acquired through lease incentives	$	1,897	$	—	$	—
Non-cash financing activities:
Borrowings and assumption of liabilities for business and asset acquisition and related intangibles	$	—	$	7,966	$	379

6.    Earnings Per Share (EPS)

	2011		2010		2009
		(in thousands, except per share data)
Basic earnings per share:
Net income attributable to Oil States International, Inc.	$	322,453	$	168,018	$	59,114
Weighted average number of shares outstanding		51,163		50,238		49,625
Basic earnings per share	$	6.30	$	3.34	$	1.19
Diluted earnings per share:
Net income attributable to Oil States International, Inc.	$	322,453	$	168,018	$	59,114
Weighted average number of shares outstanding (basic)		51,163		50,238		49,625
Effect of dilutive securities:
Options on common stock		644		630		290
2 3/8% Convertible Senior Subordinated Notes		3,023		1,647		203
Restricted stock awards and other		177		185		101
Total shares and dilutive securities		55,007		52,700		50,219
Diluted earnings per share	$	5.86	$	3.19	$	1.18

Our calculations of diluted earnings per share for the years ended December 31, 2011, 2010 and 2009 exclude 179,804 shares, 364,345 shares and 1,505,619 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.

7.    Goodwill and Other Intangible Assets

The Company does not amortize goodwill but tests for impairment using a fair value approach, at the “reporting unit” level. A reporting unit is the operating segment, or a business one level below that operating segment (the “component” level) if discrete financial information is prepared and regularly reviewed by management at the component level. The Company had three reporting units with goodwill as of December 31, 2011. There is no remaining goodwill in our drilling or tubular services reporting units subsequent to the full impairment of

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goodwill at those reporting units as of December 31, 2008. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company recognizes an impairment loss for any amount by which the carrying amount of a reporting unit’s goodwill exceeds the unit’s fair value. If our initial qualitative assessment of potential goodwill impairment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company uses, as appropriate in the current circumstance, comparative market multiples, discounted cash flow calculations and acquisition comparables to establish the reporting unit’s fair value (a Level 3 fair value measurement).

The Company amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are reviewed for impairment based on undiscounted cash flows and, if impaired, written down to fair value based on either discounted cash flows or appraised values. Intangible assets with indefinite lives are tested for impairment annually, and written down to fair value as required. As of December 31, 2011, no provision for impairment of other intangible assets was required based on the evaluations performed.

Changes in the carrying amount of goodwill for the years ended December 31, 2011 and 2010 are as follows (in thousands):

	Well Site Services
	Rental Tools  and Services			Drilling Services			Subtotal			Accommodations			Offshore Products			Tubular Services			Total
Balance as of December 31, 2009
Goodwill $	$	169,311		$	22,767		$	192,078		$	58,358		$	85,599		$	62,863		$	398,898
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—			—			(62,863	)		(180,158	)
		74,783			—			74,783			58,358			85,599			—			218,740
Goodwill acquired and purchase price adjustments		—			—			—			239,080			15,242			—			254,322
Foreign currency translation and other changes		723			—			723			1,624			(187	)		—			2,160
		75,506			—			75,506			299,062			100,654			—			475,222
Balance as of December 31, 2010
Goodwill		170,034			22,767			192,801			299,062			100,654			62,863			655,380
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—			—			(62,863	)		(180,158	)
		75,506			—			75,506			299,062			100,654			—			475,222
Goodwill acquired and purchase price adjustments		—			—			—			(9,826	)		315			—			(9,511	)
Foreign currency translation and other changes		(323	)		—			(323	)		2,087			(25	)		—			1,739
		75,183			—			75,183			291,323			100,944			—			467,450
Balance as of December 31, 2011
Goodwill		169,711			22,767			192,478			291,323			100,944			62,863			647,608
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		—			—			(62,863	)		(180,158	)
	$	75,183		$	—		$	75,183		$	291,323		$	100,944		$	—		$	467,450

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The increase in goodwill in 2010 was due to acquisitions completed during the fourth quarter of 2010. See Note 5.

The following table presents the total amount of intangibles assigned and the total accumulated amortization for major intangible asset classes as of December 31, 2011 and 2010 (in thousands):

	December 31, 2011				December 31, 2010
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets
Customer contracts/relationships	$	128,207	$	15,822	$	127,124	$	3,848
Non-compete agreements		5,164		4,310		5,117		3,704
Patents and other		18,150		3,787		18,080		3,348
	$	151,521	$	23,919	$	150,321	$	10,900

The weighted average remaining amortization period for all intangible assets, other than goodwill and indefinite- lived intangibles, was 8.6 years and 9.6 years as of December 31, 2011 and 2010, respectively. Total amortization expense is expected to be $13.1 million in 2012, $12.7 million in each of 2013, 2014 and 2015 and $12.6 million in 2016, respectively. Amortization expense was $13.3 million, $2.6 million and $3.4 million in the years ended December 31, 2011, 2010 and 2009, respectively.

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8.    Long-term Debt

As of December 31, 2011 and 2010, long-term debt consisted of the following (in thousands):

	2011		2010
US revolving credit facility, which matures December 10, 2015, with available commitments up to $500 million; secured by substantially all of our U.S. assets; commitment fee on unused portion ranged from 0.375% per annum to 0.500% in 2011 and 2010; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 2.8% for 2011 and 3.5% for 2010	$	68,065	$	345,600
US term loan, which matures December 10, 2015, of $200 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; secured by substantially all of our U.S. assets; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 2.6% for 2011 and 3.5% for 2010		190,000		200,000
Canadian revolving credit facility, which matures on December 10, 2015, with available commitments up to $250 million; secured by substantially all of our U.S. and Canadian assets; commitment fee on unused portion ranged from 0.375% per annum to 0.500% in 2011 and 0.175% per annum to 0.500% in 2010; variable interest rate payable monthly based on the Canadian prime rate or Bankers Acceptance discount rate plus applicable percentage; weighted average rate was 3.9% for 2011 and 3.6% for 2010		—		62,538
Canadian term loan, which matures December 10, 2015, of $100 million; 1.25% of aggregate principal repayable per quarter in 2011, 2.5% per quarter thereafter; secured by substantially all of our U.S. and Canadian assets; variable interest rate payable monthly based on prime or LIBOR plus applicable percentage; weighted average rate was 3.6% for 2011 and 4.5% for 2010		93,795		100,955
Australian revolving credit facility, which matures on October 15, 2013, with available commitments up to A$150 million; secured by substantially all of our Australian assets; variable interest rate payable monthly based on the Australian prime rate plus applicable percentage; weighted average rate was 6.9% for 2011		43,050		25,305
6 1/2% senior unsecured notes—due June 2019		600,000		—
2 3/8% contingent convertible senior subordinated notes, net due 2025		170,884		163,108
Subordinated unsecured notes payable to sellers of businesses, fixed interest rate of 6%, which mature in December 2012		4,000		4,000
Capital lease obligations and other debt		7,146		11,401
Total debt		1,176,940		912,907
Less: Current portion		34,435		181,175
Total long-term debt and capitalized leases	$	1,142,505	$	731,732

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Scheduled maturities of combined long-term debt as of December 31, 2011, are as follows (in thousands):

2012	$	205,318	(1)
2013		73,455
2014		30,364
2015		262,228
2016		273
Thereafter		605,302
	$	1,176,940

(1) As of December 31, 2011, we classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a noncurrent liability based on our ability and intent to refinance the 2 3/8% Notes utilizing borrowings available under our senior secured credit facilities.

The Company’s capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $2.1 million and $1.4 million, respectively, at December 31, 2011. The value of capitalized leases and the related accumulated depreciation totaled $11.5 million and $2.7 million, respectively, at December 31, 2010. In 2011, the Company’s purchased an office building previously held under a capital lease.

6^1/2% Senior Unsecured Notes

On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% senior unsecured notes (6 1/2% Notes) due 2019 through a private placement to qualified institutional buyers.

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:

Twelve Month Period Beginning June 1,	% of Principal Amount
2014		104.875	%
2015		103.250	%
2016		101.625	%
2017		100.000	%

The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Note offering in June 2011 to repay borrowings outstanding under its senior secured credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.

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2^3/8% Contingent Convertible Senior Notes

In June, 2005, we sold $125 million aggregate principal amount of 2 3/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the Securities and Exchange Commission’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.

The notes are senior unsecured obligations of the Company and bear interest at a rate of 2 3/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were included in the calculation of diluted earnings per share during periods when our average stock price exceeded the initial conversion price of $31.75 per share. The terms of the notes require that our stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price (or $38.10 per share) for at least 20 trading days in a defined period before the notes are convertible. If a note holder chooses to present their notes for conversion during a future quarter prior to the first put/call date in July 2012, they will receive cash up to $1,000 for each 2 3/8% Note plus Company common stock for any excess valuation over $1,000 using the conversion rate of the 2 3/8% Notes of approximately 31.496 multiplied by the Company’s average common stock price over a ten trading day period following presentation of the 2 3/8% Notes for conversion. As of December 31, 2011, the contingent conversion thresholds were met and, as a result, we have assumed the conversion of the notes during the first quarter of 2012 in our schedule of debt maturities above. As of December 31, 2011, we classified the $175.0 million principal amount of our 2 3/8% Notes, net of unamortized discount, as a noncurrent liability based on our ability and intent to refinance the 2 3/8% Notes utilizing borrowings available under our senior secured credit facilities. During the year ended December 31, 2011, a holder converted 10 of our 2 3/8% Notes (principal amount of $10,000) for cash of $10,000 plus 189 shares of our common stock.

The following table presents the carrying amount of our 2 3/8% Notes in our consolidated balance sheets (in thousands):

	December 31, 2011		December 31, 2010
Carrying amount of the equity component in additional paid-in capital	$	28,434	$	28,449
Principal amount of the liability component	$	174,990	$	175,000
Less: Unamortized discount		4,106		11,892
Net carrying amount of the liability	$	170,884	$	163,108

Unamortized Discount – 2 3/8% Notes

The effective interest rate of 7.17% has been applied as of the issuance date for our 2 3/8% Notes in accordance with ASC 470-20 – Debt with Conversion and Other Options. Interest expense on the 2 3/8% Notes, excluding amortization of debt issue costs, was as follows (in thousands):

	Year ended December 31,
	2011		2010		2009
Interest expense	$	11,942	$	11,405	$	10,905

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	As of December 31, 2011
Remaining period over which discount will be amortized		6 months
Conversion price	$	31.75
Number of shares to be delivered upon conversion (1)		3,220,140
Conversion value in excess of principal amount (in thousands)	$	245,922
Derivative transactions entered into in connection with the convertible notes		None

(1)  Calculation is based on the Company’s December 30, 2011 closing stock price of $76.37.

Credit Facilities

On December 10, 2010, we replaced our existing $500 million bank credit facility with $1.05 billion in senior credit facilities governed by the Amended and Restated Credit Agreement. The new credit facilities totaled $1.05 billion of available commitments consisting of revolving borrowings, up to $750 million, and term borrowings, of $300 million. The Company borrowed all of the term commitment in connection with the acquisition of The MAC. Under these senior secured revolving credit facilities with a group of banks, up to $350 million is available in the form of loans denominated in Canadian dollars and may be made to the Company’s principal Canadian operating subsidiaries. The facilities mature on December 10, 2015. The current principal balance of the term loans is repayable at a rate of 2.5% per quarter of the aggregate principal amount until maturity on December 10, 2015 when the remaining principal is due. Amounts borrowed under these facilities bear interest, at the Company’s election, at either:

• a variable rate equal to LIBOR (or, in the case of Canadian dollar denominated loans, the Bankers’ Acceptance discount rate) plus a margin ranging from 2.0% to 3.0%; or

• an alternate base rate equal to the higher of the bank’s prime rate and the federal funds effective rate (or, in the case of Canadian dollar denominated loans, the Canadian Prime Rate).

Commitment fees ranging from 0.375% to 0.50% per year are paid on the undrawn portion of the facilities, depending upon our leverage ratio.

The credit facilities are guaranteed by all of the Company’s active domestic subsidiaries and, in some cases, the Company’s Canadian and other foreign subsidiaries. The credit facilities are secured by a first priority lien on all the Company’s inventory, accounts receivable and other material tangible and intangible assets, as well as those of the Company’s active subsidiaries. However, no more than 65% of the voting stock of any foreign subsidiary is required to be pledged if the pledge of any greater percentage would result in adverse tax consequences.

The Credit Agreement, which governs our credit facilities, contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA of no greater than 3.25 to 1.0 in 2012 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of these 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, 2011, we were in compliance with our debt covenants and expect to continue to be in compliance during 2012. The credit facilities also contain negative covenants that limit the Company’s ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.

Under the Company’s credit facilities, the occurrence of specified change of control events involving our company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facilities and cause them to become immediately due and payable in full.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of December 31, 2011, we had $351.9 million outstanding under these facilities and an additional $25.1 million of outstanding letters of credit, leaving $656.8 million available to be drawn under the facilities.

On July 13, 2011, The MAC entered into a A$150 million revolving loan facility governed by a Facility Agreement (the Facility Agreement) between The MAC and National Australia Bank Limited, which is guaranteed by the Company. The Facility Agreement amended The MAC’s existing A$75 million revolving loan facility on substantially the same terms, including the maturity date of the Facility Agreement of November 30, 2013. As of December 31, 2011, we had $43.1 million outstanding under the Australian facility.

Interest expense on the consolidated statements of income is net of capitalized interest of $5.3 million, $0.2 million and $0.1 million, respectively, for the years ended December 31, 2011, 2010 and 2009.

9.    Stock Repurchase Program

On August 27, 2010, the Company announced that its Board of Directors authorized $100 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which expired on December 31, 2009. The Company presently has approximately 51.3 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2012. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. Through December 31, 2011, a total of $12.6 million of our stock (209,300 shares) had been repurchased under this program, leaving a total authorization of up to approximately $87.4 million remaining available under the program.

10.    Retirement Plans

The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $11.1 million, $7.7 million and $7.3 million, respectively, related to matching contributions under its various defined contribution plans during the years ended December 31, 2011, 2010 and 2009, respectively.

11.    Income Taxes

Consolidated pre-tax income (loss) for the years ended December 31, 2011, 2010 and 2009 consisted of the following (in thousands):

	2011		2010		2009
US operations	$	193,091	$	68,921	$	(41,354	)
Foreign operations		261,978		171,707		147,063
Total	$	455,069	$	240,628	$	105,709

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The components of the income tax provision for the years ended December 31, 2011, 2010 and 2009 consisted of the following (in thousands):

	2011		2010			2009
Current:
Federal	$	48,253	$	25,237		$	12,403
State		1,769		1,122			674
Foreign		48,921		44,249			45,700
		98,943		70,608			58,777
Deferred:
Federal		15,862		(1,572	)		(15,239	)
State		2,206		(58	)		(566	)
Foreign		14,636		3,045			3,125
		32,704		1,415			(12,680	)
Total Provision	$	131,647	$	72,023		$	46,097

The provision for taxes differs from an amount computed at statutory rates as follows for the years ended December 31, 2011, 2010 and 2009 consisted (in thousands):

	2011			2010			2009
Federal tax expense at statutory rates	$	159,274		$	84,220		$	36,998
Effect of foreign income tax, net		(33,818	)		(12,796	)		(12,162	)
Nondeductible goodwill		—			—			18,373
Nondeductible acquisition costs		183			2,315			—
Other nondeductible expenses		3,194			1,454			1,518
State tax expense, net of federal benefits		3,975			1,017			127
Domestic manufacturing deduction		(1,839	)		(978	)		(80	)
Uncertain tax positions adjustments, net		(1,585	)		(1,036	)		1,139
Other, net		2,263			(2,173	)		184
Net income tax provision	$	131,647		$	72,023		$	46,097

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows (in thousands):

	2011				2010
Deferred tax assets:
Net operating loss carryforward	$	—			$	1,976
Allowance for doubtful accounts		1,232		��		752
Allowance for inventory obsolescence		6,466				4,775
Employee benefits		14,655				11,823
Deductible goodwill and other intangibles		11,586				10,870
Other reserves		5,432				3,467
Depreciation		1,045				—
Foreign tax credit carryover		8,538				1,259
Other		3,373				3,872
Gross deferred tax asset		52,327				38,794
Less: valuation allowance		—				421
Net deferred tax asset		52,327				38,373
Deferred tax liabilities:
Depreciation		(130,793	)			(88,872	)
Deferred revenue		(1,705	)			(1,466	)
Intangibles		(5,082	)			(13,568	)
Accrued liabilities		(4,330	)			(1,132	)
Lower of cost or market		(2,141	)			(3,846	)
Convertible notes		(1,514	)			(4,218	)
Other		(3,674	)			(3,289	)
Deferred tax liability		(149,239	)			(116,391	)
Net deferred tax liability	$	(96,912	)		$	(78,018	)

Reclassifications of the Company’s deferred tax balance based on net current items and net non-current items as of December 31, 2011 and 2010 are as follows (in thousands):

	2011			2010
Current deferred tax liability	$	(5,298	)	$	(1,462	)
Long-term deferred tax liability		(91,614	)		(76,556	)
Net deferred tax liability	$	(96,912	)	$	(78,018	)

Our primary deferred tax assets at December 31, 2011, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, allowance for inventory obsolescence and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.

Our income tax provision for the year ended December 31, 2011 totaled $131.6 million, or 28.9% of pretax income, compared to $72.0 million, or 29.9% of pretax income, for the year ended December 31, 2010.

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Appropriate U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted in the near future. The cumulative amount of undistributed earnings of foreign subsidiaries that the Company intends to permanently reinvest, and upon which foreign taxes have been accrued or paid but no deferred US income taxes have been provided is $888 million at December 31, 2011, the majority of which has been generated in Canada. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to US income taxes (subject to adjustment for foreign tax credits) and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits.

The American Jobs Creation Act of 2004 that was signed into law in October 2004 introduced a requirement for companies to disclose any penalties imposed on them or any of their consolidated subsidiaries by the IRS for failing to satisfy tax disclosure requirements relating to “reportable transactions.” During the year ended December 31, 2011, no penalties were imposed on the Company or its consolidated subsidiaries for failure to disclose reportable transactions to the IRS.

The Company files tax returns in the jurisdictions in which they are required. All of these returns are subject to examination or audit and possible adjustment as a result of assessments by taxing authorities. The Company believes that it has recorded sufficient tax liabilities and does not expect the resolution of any examination or audit of its tax returns would have a material adverse effect on its operating results, financial condition or liquidity.

Tax years subsequent to 2008 remain open to U.S. federal tax audit and, because of Net Operating Losses (NOL’s) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL’s available for tax carryforward. Our Canadian subsidiaries’ federal tax returns subsequent to 2007 are subject to audit by the Canada Revenue Agency. Our Australian subsidiary’s federal tax returns subsequent to 2006 are subject to audit by the Australian Taxation Office.

We account for uncertain tax positions using a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

The total amount of unrecognized tax benefits as of December 31, 2011 was $1.8 million. The unrecognized tax benefits, if recognized, would affect the effective tax rate. The Company accrues interest and penalties related to unrecognized tax benefits as a component of the Company’s provision for income taxes. As of December 31, 2011 and 2010, the Company had accrued $2.3 million and $2.7 million, respectively, of interest expense and penalties.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	2011			2010			2009
Balance as of January 1st	$	3,044		$	4,031		$	4,274
Additions for tax positions of prior years		—			128			2,136
Reductions for tax positions of prior years		(798	)		—			—
Lapse of the applicable statute of limitations		(399	)		(1,115	)		(2,379	)
Balance as of December 31st	$	1,847		$	3,044		$	4,031

It is reasonably possible that the amount of unrecognized tax benefits will change during the next twelve months due to the closing of the statute of limitations and that change, if it were to occur, could have a favorable impact on our results of operation.

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12. Commitments and Contingencies

The Company leases a portion of its equipment, office space, computer equipment, automobiles and trucks under leases which expire at various dates.

Minimum future operating lease obligations in effect at December 31, 2011, are as follows (in thousands):

	Operating Leases
2012	$	11,821
2013		10,056
2014		8,970
2015		5,803
2016		2,590
Thereafter		8,469
Total	$	47,709

Rental expense under operating leases was $14.5 million, $12.9 million and $10.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

The Company is a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials as a result of its products or operations. Some of these claims relate to matters occurring prior to its acquisition of businesses, and some relate to businesses it has sold. In certain cases, the Company is entitled to indemnification from the sellers of businesses, and in other cases, it has indemnified the buyers of businesses from it. Although the Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on it, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its consolidated financial position, results of operations or liquidity.

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13.     Stock-Based Compensation

Current accounting standards require companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period.

The fair value of each option grant is estimated on the date of grant using a Black-Scholes option pricing model that uses the assumptions noted in the following table. The risk-free interest rate is based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2009, 2010 and 2011 was based on a formula considering the vesting period, term of the options awarded and past experience.

	2011			2010			2009
Risk-free weighted interest rate		1.7	%		2.1	%		1.8	%
Expected life (in years)		4.1			4.3			4.3
Expected volatility		55	%		55	%		55	%

The following table summarizes stock option activity for each of the three years ended December 31, 2011:

	Options			Weighted Average Exercise Price		Weighted Average Contractual Life (Years)		Aggregate Intrinsic Value (Thousands)
Outstanding Options at December 31, 2008		1,947,416			28.13		3.7		2,706
Granted		768,650			17.20
Exercised		(199,615	)		17.33
Forfeited		(34,500	)		32.83
Outstanding Options at December 31, 2009		2,481,951			25.55		3.6		34,618
Granted		417,250			37.67
Exercised		(866,436	)		26.96
Forfeited		(65,375	)		27.75
Outstanding Options at December 31, 2010		1,967,390			27.42		3.5		72,138
Granted		186,200			75.34
Exercised		(517,202	)		27.37
Forfeited		(53,125	)		41.85
Outstanding Options at December 31, 2011		1,583,263			32.59		3.4		69,311

The weighted average fair values of options granted during 2011, 2010 and 2009 were $33.23, $17.13, and $7.76 per share, respectively. All options awarded in 2011 had a term of ten years and were granted with exercise prices at the grant date closing market price. The total intrinsic value of options exercised during 2011, 2010 and 2009 were $24.9 million, $19.9 million and $3.2 million, respectively. Cash received by the Company from option exercises during 2011, 2010 and 2009 totaled $14.2 million, $23.4 million and $3.5 million, respectively. The tax benefit realized for the tax deduction from stock options exercised during 2011, 2010 and 2009 totaled $7.8 million, $6.1 million and $1.2 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes information for stock options outstanding at December 31, 2011:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number Outstanding as of 12/31/2011		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable as of 12/31/2011		Weighted Average Exercise Price
$11.49 - $ 16.65		574,050		2.72	$	15.80		277,576	$	14.90
$24.52 - $ 37.67		814,888		2.77	$	34.84		389,502	$	33.88
$42.88 - $ 75.41		194,325		8.11	$	72.75		22,600	$	56.59
$11.49 - $ 75.41		1,583,263		3.41	$	32.59		689,678	$	26.99

At December 31, 2011, a total of 1,499,997 shares were available for future grant under the Equity Participation Plan.

During 2011, we awarded 217,415 shares of restricted stock valued at a total of $16.3 million. Of the restricted stock awards granted in 2011, a total of 200,504 awards vest in four equal annual installments starting in February 2012. A total of 233,493 shares of restricted stock were awarded in 2010 with an aggregate value of $9.1 million. A total of 192,027 shares of restricted stock were awarded in 2009 with an aggregate value of $3.6 million.

Stock based compensation pre-tax expense recognized in the years ended December 31, 2011, 2010 and 2009 totaled $14.6 million, $12.6 million and $11.5 million, or $0.20, $0.18 and $0.13 per diluted share after tax, respectively. At December 31, 2011, $24.0 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.

Deferred Compensation Plan

The Company maintains a deferred compensation plan (Deferred Compensation Plan). This plan is available to directors and certain officers and managers of the Company. The plan allows participants to defer the receipt of all or a portion of their directors’ fees and/or salary and annual bonuses. Employee contributions to the Deferred Compensation Plan are matched by the Company at the same percentage as if the employee was a participant in the Company’s 401(k) Retirement Plan and was not subject to the IRS limitations on match-eligible compensation. The Deferred Compensation Plan also permits the Company to make discretionary contributions to any employee’s account. Director’s contributions are not matched by the Company. Since inception of the plan, this discretionary contribution provision has been limited to a matching of the participants’ contributions on a basis equivalent to matching permitted under the Company’s 401(k) Retirement Savings Plan. The vesting of contributions to the participants’ accounts is also equivalent to the vesting requirements of the Company’s 401(k) Retirement Savings Plan. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (Trust) and, therefore, are available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest the assets in their individual accounts, including any discretionary contributions by the Company, in ten pre-approved mutual funds held by the Trust which cover a variety of securities and mutual funds. Prior to November 1, 2003, participants also had the ability to direct the Plan Administrator to invest the assets in their accounts in Company common stock. In addition, participants currently have the right to request that the Plan Administrator to re-allocate the portfolio of investments (i.e. cash or mutual funds) in the participants’ individual accounts within the Trust. Current balances invested in Company common stock may not be further increased. Company contributions are in the form of cash. Distributions from the plan are generally made upon the participants’ termination as a director and/or employee, as applicable, of the Company. Participants receive payments from the Plan in cash. At December 31, 2011, Trust assets totaled $9.5 million, including 17,459 shares of common stock of the Company which are

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included as treasury stock at a value of $0.2 million. The remaining $9.3 million of Trust assets are classified as “other noncurrent assets” in the Company’s consolidated balance sheet. The fair value of the investments was based on quoted market prices in active markets (a Level 1 fair value measurement). Amounts payable to the plan participants at December 31, 2011, including the fair value of the shares of the Company’s common stock that are reflected as treasury stock, was $10.6 million and is classified as “Other noncurrent liabilities” in the consolidated balance sheet. The Company accounts for the Deferred Compensation Plan in accordance with current accounting standards regarding the accounting for deferred compensation arrangements where amounts earned are held in a Rabbi Trust and invested.

In accordance with current accounting standards, all fair value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of income. Increases or decreases in the fair value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of income. In response to the changes in total fair value of the Company’s common stock held by the Trust, the Company recorded net compensation expense adjustments to the liability of $0.2 million in 2011, $0.4 million in 2010 and $0.4 million in 2009.

14.     Segment and Related Information

In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, accommodations, offshore products and tubular services. The Company’s reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. The separate business lines within the well site services segment have been disclosed to provide additional detail for that segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Financial information by industry segment for each of the three years ended December 31, 2011, 2010 and 2009, is summarized in the following table in thousands. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in earnings (loss) of unconsolidated affiliates			Capital expenditures		Total assets
2011
Well site services —
Rental tools and services	$	487,941	$	41,612	$	120,849		$	—		$	81,024	$	462,189
Drilling services		165,903		19,818		20,394			—			29,477		128,721
Total well site services		653,844		61,430		141,243			—			110,501		590,910
Accommodations		864,701		110,705		248,977			1			348,504		1,789,868
Offshore products		585,818		13,454		94,666			(847	)		19,987		622,466
Tubular services		1,374,817		1,758		64,422			683			8,129		645,422
Corporate and eliminations		—		800		(41,785	)		—			361		54,975
Total	$	3,479,180	$	188,147	$	507,523		$	(163	)	$	487,482	$	3,703,641
2010
Well site services —
Rental tools and services	$	342,953	$	40,859	$	47,326		$	—		$	42,884	$	383,778
Drilling services		133,214		24,149		576			—			10,300		108,163
Total well site services		476,167		65,008		47,902			—			53,184		491,941
Accommodations		537,690		45,694		151,417			(25	)		107,347		1,491,682
Offshore products		428,963		11,496		60,664			—			13,299		520,944
Tubular services		969,164		1,301		35,941			264			7,889		458,808
Corporate and eliminations		—		703		(40,342	)		—			488		52,624
Total	$	2,411,984	$	124,202	$	255,582		$	239		$	182,207	$	3,015,999
2009
Well site services —
Rental tools and services	$	234,121	$	40,900	$	(97,844	)	$			$	31,915	$	340,792
Drilling services		71,175		26,343		(16,345	)					11,048		116,555
Total well site services		305,296		67,243		(114,189	)					42,963		457,347
Accommodations		481,402		37,892		140,665			203			68,381		573,011
Offshore products		509,388		10,945		81,049			—			12,114		510,399
Tubular services		812,164		1,443		41,758			1,249			354		360,652
Corporate and eliminations		—		585		(30,554	)		—			676		30,977
Total	$	2,108,250	$	118,108	$	118,729		$	1,452		$	124,488	$	1,932,386

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Financial information by geographic segment for each of the three years ended December 31, 2011, 2010 and 2009, is summarized below in thousands. Revenues in the US include export sales. Revenues are attributable to countries based on the location of the entity selling the products or performing the services. Total assets are attributable to countries based on the physical location of the entity and its operating assets and do not include intercompany balances.

	United States		Canada		Australia		United Kingdom		Other Non-US		Total
2011
Revenues from unaffiliated customers	$	2,424,669	$	590,242	$	197,095	$	130,407	$	136,767	$	3,479,180
Long-lived assets		714,541		608,054		827,271		18,357		39,996		2,208,219
2010
Revenues from unaffiliated customers	$	1,708,709	$	512,288	$	—	$	77,180	$	113,807	$	2,411,984
Long-lived assets		639,120		502,322		724,522		17,275		28,088		1,911,327
2009
Revenues from unaffiliated customers	$	1,460,810	$	460,492	$	—	$	105,222	$	81,726	$	2,108,250
Long-lived assets		541,563		424,523		—		18,352		22,327		1,006,765

No customers accounted for more than 10% of the Company’s revenues in any of the years ended December 31, 2011, 2010 and 2009. Equity in net income of unconsolidated affiliates is not included in operating income.

15.     Valuation Allowances

Activity in the valuation accounts was as follows (in thousands):

	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (net of recoveries)			Translation and Other, Net			Balance at End of Period
Year Ended December 31, 2011:
Allowance for doubtful accounts receivable	$	4,100	$	2,239	$	(2,310	)	$	(66	)	$	3,963
Allowance for inventory obsolescence		8,454		2,366		(783	)		(7	)		10,030
Liabilities related to discontinued operations		2,268		—		(143	)		—			2,125
Year Ended December 31, 2010:
Allowance for doubtful accounts receivable	$	4,946	$	869	$	(1,915	)	$	200		$	4,100
Allowance for inventory obsolescence		8,279		1,288		(510	)		(603	)		8,454
Liabilities related to discontinued operations		2,411		—		(143	)		—			2,268
Year Ended December 31, 2009:
Allowance for doubtful accounts receivable	$	4,168	$	3,048	$	(2,479	)	$	209		$	4,946
Allowance for inventory obsolescence		6,712		2,264		(867	)		170			8,279
Liabilities related to discontinued operations		2,544		—		(133	)		—			2,411

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16.     Quarterly Financial Information (Unaudited)

The following table summarizes quarterly financial information for 2011 and 2010 (in thousands, except per share amounts):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2011
Revenues	$	760,441	$	820,317	$	902,621	$	995,801
Gross profit(1)		186,043		203,539		236,766		253,565
Net income		62,077		74,243		91,851		94,282
Basic earnings per share		1.22		1.45		1.79		1.84
Diluted earnings per share		1.13		1.34		1.67		1.72
2010
Revenues	$	532,345	$	594,532	$	588,347	$	696,759
Gross profit(1)		125,835		125,050		139,745		147,060
Net income (loss)(2)		40,243		37,477		46,346		43,952
Basic earnings (loss) per share(2)		0.81		0.75		0.92		0.87
Diluted earnings (loss) per share(2)		0.78		0.71		0.88		0.82

(1) Represents “revenues” less “product costs” and “service and other costs” included in the Company’s consolidated statements of income.

(2) The gross profit and net income in the fourth quarter of 2010 included $6.3 million in acquisition costs related to the three acquisitions in the quarter.

Amounts are calculated independently for each of the quarters presented. Therefore, the sum of the quarterly amounts may not equal the total calculated for the year.

17.     Condensed Consolidating Financial Information

Certain wholly-owned subsidiaries, as detailed below (the Guarantor Subsidiaries), have fully and unconditionally guaranteed all of the 6 1/2% Notes issued by Oil States International, Inc. in 2011 and all of the 2 3/8% Notes issued in 2005.

The following condensed consolidating financial information is included so that separate financial statements of the Guarantor Subsidiaries are not required to be filed with the Commission. The condensed consolidating financial information presents investments in both consolidated and unconsolidated affiliates using the equity method of accounting.

The following condensed consolidating financial information presents: consolidating statements of income for each of the years ended December 31, 2011, 2010 and 2009, condensed consolidating balance sheets as December 31, 2011 and December 31, 2010 and the statements of cash flows for each of the years ended December 31, 2011, 2010 and 2009 of (a) the Company, parent/guarantor, (b) Acute Technological Services, Inc., Capstar Drilling LP, L.L.C., Capstar Holding, L.L.C., Capstar Drilling, Inc., Capstar Drilling GP, L.L.C., General Marine Leasing, LLC, Oil States Energy Services, Inc., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, LLC, PTI Group USA LLC, PTI Mars Holdco 1, LLC, Sooner Inc., Sooner Pipe, L.L.C., Sooner Holding Company, Specialty Rental Tools & Supply, L.L.C., Stinger Wellhead Protection, Incorporated, and Well Testing, Inc., the Guarantor Subsidiaries, (c) the non-guarantor subsidiaries, (d) consolidating adjustments necessary to consolidate the Company and its subsidiaries and (e) the Company on a consolidated basis.

98

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Income

	Year Ended December 31, 2011
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	2,428,651		$	1,050,529		$	—		$	3,479,180
Intercompany revenues		—			19,857			966			(20,823	)		—
Total revenues		—			2,448,508			1,051,495			(20,823	)		3,479,180
OPERATING EXPENSES
Cost of sales and services		—			1,998,222			605,295			(4,250	)		2,599,267
Intercompany cost of sales and services		—			15,462			771			(16,233	)		—
Selling, general and administrative expenses		39,151			84,770			58,513			—			182,434
Depreciation and amortization expense		800			81,479			105,881			(13	)		188,147
Other operating (income)/expense		1,834			(958	)		931			2			1,809
Operating income (loss)		(41,785	)		269,533			280,104			(329	)		507,523
Interest expense, net of capitalized interest		(52,364	)		(1,238	)		(76,693	)		72,789			(57,506	)
Interest income		15,252			6,575			52,661			(72,788	)		1,700
Equity in earnings (loss) of unconsolidated affiliates		354,524			37,932			(846	)		(391,773	)		(163	)
Other income		41,336			(37,926	)		105			—			3,515
Income before income taxes		316,963			274,876			255,331			(392,101	)		455,069
Income tax provision		5,490			(75,869	)		(61,268	)		—			(131,647	)
Net income		322,453			199,007			194,063			(392,101	)		323,422
Less: Net income attributable to non-controlling interest		—			—			926			43			969
Net income attributable to Oil States International, Inc.	$	322,453		$	199,007		$	193,137		$	(392,144	)	$	322,453

99

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Income

	Year Ended December 31, 2010
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	1,698,363		$	713,621		$	—		$	2,411,984
Intercompany revenues		—			28,359			931			(29,290	)		—
Total revenues		—			1,726,722			714,552			(29,290	)		2,411,984
OPERATING EXPENSES
Cost of sales and services		—			1,433,931			447,885			(7,522	)		1,874,294
Intercompany cost of sales and services		—			21,294			473			(21,767	)		—
Selling, general and administrative expenses		33,272			81,225			36,368			—			150,865
Depreciation and amortization expense		703			74,151			49,355			(7	)		124,202
Other operating (income)/expense		6,367			(433	)		1,107			—			7,041
Operating income (loss)		(40,342	)		116,554			179,364			6			255,582
Interest expense		(14,906	)		(680	)		(4,746	)		4,058			(16,274	)
Interest income		471			1,405			2,934			(4,059	)		751
Equity in earnings of unconsolidated affiliates		170,407			25,096			(25	)		(195,239	)		239
Other income/(expense)		33,725			(31,544	)		(1,851	)		—			330
Income before income taxes		149,355			110,831			175,676			(195,234	)		240,628
Income tax provision		18,664			(42,357	)		(48,330	)		—			(72,023	)
Net income		168,019			68,474			127,346			(195,234	)		168,605
Less: Net income attributable to non-controlling interest		—			—			577			10			587
Net income attributable to Oil States International, Inc.	$	168,019		$	68,474		$	126,769		$	(195,244	)	$	168,018

100

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Income

	Year Ended December 31, 2009
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
REVENUES
Operating revenues	$	—		$	1,455,447		$	652,803		$	—		$	2,108,250
Intercompany revenues		—			7,005			3,363			(10,368	)		—
Total revenues		—			1,462,452			656,166			(10,368	)		2,108,250
OPERATING EXPENSES
Cost of sales and services		—			1,233,878			408,748			(2,428	)		1,640,198
Intercompany cost of sales and services		—			4,562			3,386			(7,948	)		—
Selling, general and administrative expenses		30,069			75,849			33,375			—			139,293
Depreciation and amortization expense		585			75,699			41,831			(7	)		118,108
Impairment of goodwill		—			94,528			—			—			94,528
Other operating (income)/expense		(100	)		(19,153	)		16,639			8			(2,606	)
Operating income (loss)		(30,554	)		(2,911	)		152,187			7			118,729
Interest expense, net of capitalized interest		(13,737	)		(5,135	)		(953	)		4,559			(15,266	)
Interest income		4,384			235			320			(4,559	)		380
Equity in earnings of unconsolidated affiliates		69,012			8,675			204			(76,439	)		1,452
Other income/(expense)		28,716			(27,005	)		(1,297	)		—			414
Income before income taxes		57,821			(26,141	)		150,461			(76,432	)		105,709
Income tax provision		3,121			(2,290	)		(46,928	)		—			(46,097	)
Net income		60,942			(28,431	)		103,533			(76,432	)		59,612
Less: Net income attributable to non-controlling interest		—			—			490			8			498
Net income attributable to Oil States International, Inc.	$	60,942		$	(28,431	)	$	103,043		$	(76,440	)	$	59,114

101

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Balance Sheets

	December 31, 2011
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	(274	)	$	1,900		$	70,095		$	—		$	71,721
Accounts receivable, net		974			461,033			270,233			—			732,240
Inventories, net		—			539,066			114,824			(192	)		653,698
Prepaid expenses and other current assets		10,780			7,902			13,318			—			32,000
Total current assets		11,480			1,009,901			468,470			(192	)		1,489,659
Property, plant and equipment, net		1,530			464,399			1,091,325			(166	)		1,557,088
Goodwill, net		—			172,598			294,852			—			467,450
Other intangible assets, net		—			31,372			96,230			—			127,602
Investments in unconsolidated affiliates		2,096,505			235,617			23,517			(2,347,878	)		7,761
Long-term intercompany receivables (payables)		831,477			(459,735	)		(378,706	)		6,964			—
Other noncurrent assets		41,234			458			12,389			—			54,081
Total assets	$	2,982,226		$	1,454,610		$	1,608,077		$	(2,341,272	)	$	3,703,641
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	42,693		$	206,125		$	100,140		$	(1	)	$	348,957
Income taxes		(49,069	)		51,986			7,478			—			10,395
Current portion of long-term debt and capitalized leases		20,018			4,404			10,013			—			34,435
Deferred revenue		—			47,227			28,270			—			75,497
Other current liabilities		—			5,382			283			—			5,665
Total current liabilities		13,642			315,124			146,184			(1	)		474,949
Long-term debt and capitalized leases		1,008,969			6,437			127,099			—			1,142,505
Deferred income taxes		(13,146	)		69,751			40,772			—			97,377
Other noncurrent liabilities		10,605			8,634			6,748			(449	)		25,538
Total liabilities		1,020,070			399,946			320,803			(450	)		1,740,369
Stockholders’ equity		1,962,156			1,054,664			1,286,368			(2,341,032	)		1,962,156
Non-controlling interest		—			—			906			210			1,116
Total stockholders’ equity		1,962,156			1,054,664			1,287,274			(2,340,822	)		1,963,272
Total liabilities and stockholders’ equity	$	2,982,226		$	1,454,610		$	1,608,077		$	(2,341,272	)	$	3,703,641

102

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Balance Sheets

	December 31, 2010
	Oil States International, Inc. (Parent/ Guarantor			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	(180	)	$	1,170		$	95,360		$	—		$	96,350
Accounts receivable, net		852			303,771			174,116			—			478,739
Inventories, net		—			429,427			72,008			—			501,435
Prepaid expenses and other current assets		6,243			10,796			6,441			—			23,480
Total current assets		6,915			745,164			347,925			—			1,100,004
Property, plant and equipment, net		1,930			394,335			856,422			(30	)		1,252,657
Goodwill, net		—			171,135			304,087			—			475,222
Other intangible assets, net		—			34,894			104,527			—			139,421
Investments in unconsolidated affiliates		1,723,711			200,652			569			(1,918,995	)		5,937
Long-term intercompany receivables (payables)		567,560			(50,475	)		(524,050	)		6,965			—
Other noncurrent assets		33,562			336			8,860			—			42,758
Total assets	$	2,333,678		$	1,496,041		$	1,098,340		$	(1,912,060	)	$	3,015,999
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	28,650		$	202,503		$	73,585		$	1		$	304,739
Income taxes		(31,363	)		30,919			5,048			—			4,604
Current portion of long-term debt and capitalized leases		173,122			2,424			5,629			—			181,175
Deferred revenue		—			44,981			15,866			—			60,847
Other current liabilities		—			1,727			1,083			—			2,810
Total current liabilities		170,409			282,554			101,211			1			554,175
Long-term debt and capitalized leases		536,747			9,774			185,211			—			731,732
Deferred income taxes		(10,816	)		48,642			43,372			—			81,198
Other noncurrent liabilities		9,432			10,141			837			(449	)		19,961
Total liabilities		705,772			351,111			330,631			(448	)		1,387,066
Stockholders’ equity		1,627,906			1,144,930			766,848			(1,911,778	)		1,627,906
Non-controlling interest		—			—			861			166			1,027
Total stockholders’ equity		1,627,906			1,144,930			767,709			(1,911,612	)		1,628,933
Total liabilities and stockholders’ equity	$	2,333,678		$	1,496,041		$	1,098,340		$	(1,912,060	)	$	3,015,999

103

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2011
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments			Consolidated Oil States International, Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(61,274	)	$	90,496		$	186,801			(110	)	$	215,913
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(361	)		(143,909	)		(343,322	)		110			(487,482	)
Acquisitions of businesses, net of cash acquired		—			(2,412	)		—			—			(2,412	)
Proceeds from sale of buildings and equipment		—			2,339			3,610			—			5,949
Other, net		—		��	(3,259	)		(1,751	)		—			(5,010	)
Net cash provided by (used in) investing activities		(361	)		(147,241	)		(341,463	)		—			(488,955	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		(278,676	)		—			(38,060	)		—			(316,736	)
6 1/2 % senior notes issued		600,000			—			—			—			600,000
Term loan borrowings (repayments)		(10,000	)		—			(4,972	)		—			(14,972	)
Debt and capital lease repayments		(19	)		(455	)		(2,055	)		—			(2,529	)
Issuance of common stock from share-based payment arrangements		14,154			—			—			—			14,154
Purchase of treasury stock		(12,632	)		—			—			—			(12,632	)
Excess tax benefits from share-based payment arrangements		8,583			—			—			—			8,583
Payment of financing costs		(13,205	)					(259	)		—			(13,464	)
Proceeds from (funding of) accounts and notes with affiliates, net		(243,952	)		59,869			184,083			—			—
Other, net		(2,712	)		(1,805	)		1			—			(4,516	)
Net cash provided by (used in) financing activities		61,541			57,609			138,738			—			257,888
Effect of exchange rate changes on cash		—			9			(9,341	)		—			(9,332	)
Net change in cash and cash equivalents from continuing operations		(94	)		873			(25,265	)		—			(24,486	)
Net cash used in discontinued operations operating activities		—			(143	)		—			—			(143	)
Cash and cash equivalents, beginning of period		(180	)		1,170			95,360			—			96,350
Cash and cash equivalents, end of period	$	(274	)	$	1,900		$	70,095			—		$	71,721

104

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2010
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(40,342	)	$	95,961		$	175,303			—	$	230,922
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(490	)		(68,249	)		(113,468	)		—		(182,207	)
Acquisition of businesses, net of cash acquired		—			(71,992	)		(637,583	)		—		(709,575	)
Proceeds from sale of buildings and equipment		—			2,260			474			—		2,734
Other, net		—			(8,949	)		8,317			—		(632	)
Net cash provided by (used in) investing activities		(490	)		(146,930	)		(742,260	)		—		(889,680	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		346,742			—			387			—		347,129
Term loan borrowings		200,000			—			100,955			—		300,955
Debt and capital lease payments		(30	)		(403	)		(54	)		—		(487	)
Issuance of common stock from share-based payment arrangements		23,361			—			—			—		23,361
Excess tax benefits from share-based payment arrangements		4,029			—			—			—		4,029
Payment of financing costs		(24,548	)		—			—			—		(24,548	)
Proceeds from (funding of) accounts and notes with affiliates, net		(514,643	)		52,539			462,104			—		—
Other, net		(1,407	)		—			—			—		(1,407	)
Net cash provided by (used in) financing activities		33,504			52,136			563,392			—		649,032
Effect of exchange rate changes on cash		—			(2	)		16,479			—		16,477
Net change in cash and cash equivalents from continuing operations		(7,328	)		1,165			12,914			—		6,751
Net cash used in discontinued operations operating activities		—			(143	)		—			—		(143	)
Cash and cash equivalents, beginning of period		7,148			148			82,446			—		89,742
Cash and cash equivalents, end of period	$	(180	)	$	1,170		$	95,360			—	$	96,350

105

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2009
	Oil States International, Inc. (Parent/ Guarantor)			Guarantor Subsidiaries			Other Subsidiaries (Non- Guarantors)			Consolidating Adjustments		Consolidated Oil States International, Inc.
	(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(90,736	)	$	363,176		$	180,922			—	$	453,362
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, including capitalized interest		(677	)		(48,403	)		(75,408	)		—		(124,488	)
Acquisition of businesses, net of cash acquired		—			—			18			—		18
Proceeds from sale of buildings and equipment		—			2,261			578			—		2,839
Proceeds from sale of investments and collection of notes receivable		—			21,166			—			—		21,166
Other, net		(1	)		(153	)		(1,989	)		—		(2,143	)
Net cash provided by (used in) investing activities		(678	)		(25,129	)		(76,801	)		—		(102,608	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Revolving credit borrowings (repayments), net		(230,198	)		—			(64,562	)		—		(294,760	)
Debt and capital lease payments		(27	)		(4,880	)		(54	)		—		(4,961	)
Issuance of common stock from share-based payment arrangements		3,460			—			—			—		3,460
Proceeds from (funding of) accounts and notes with affiliates, net		325,890			(334,059	)		8,169					—
Other, net		(511	)		941			(942	)		—		(512	)
Net cash provided by (used in) financing activities		98,614			(337,998	)		(57,389	)		—		(296,773	)
Effect of exchange rate changes on cash		—			—			5,695			—		5,695
Net change in cash and cash equivalents from continuing operations		7,200			49			52,427			—		59,676
Net cash used in discontinued operations operating activities		—			(133	)		—			—		(133	)
Cash and cash equivalents, beginning of period		(52	)		232			30,019			—		30,199
Cash and cash equivalents, end of period	$	7,148		$	148		$	82,446			—	$	89,742

106

Exhibit Index

Exhibit No.		Description
2.1	—	Scheme Implementation Deed, dated October 15, 2010, by and between Oil States International, Inc. and The MAC Services Group Limited (incorporated by reference to Exhibit 2.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 15, 2010 (File No. 001-16337)).
3.1	—	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
3.2	—	Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).
3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1, as filed with the Commission on November 7, 2000 (File No. 333-43400)).
4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003 (File No. 001-16337)).
4.4	—	Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.4 to Oil States’ Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).
4.5	—	Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Oil States’ Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).
4.6	—	Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 to Oil States’ Current Reports on Form 8-K as filed with the Commission on June 23, 2005 and July 13, 2005 (File No. 001-16337)).
4.7	—	Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).
4.8	—	Supplemental Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).

10.1	—	Combination Agreement dated as of July 31, 2000 by and among Oil States International, Inc., HWC Energy Services, Inc., Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI Group Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-1, as filed with the Commission on August 10, 2000 (File No. 333-43400)).
10.2	—	Plan of Arrangement of PTI Group Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.3	—	Support Agreement between Oil States International, Inc. and PTI Holdco (incorporated by reference to Exhibit 10.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.4	—	Voting and Exchange Trust Agreement by and among Oil States International, Inc., PTI Holdco and Montreal Trust Company of Canada (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.5**	—	Second Amended and Restated 2001 Equity Participation Plan effective March 30, 2009 (incorporated by reference to Exhibit 10.5 to Oil States’ Current Report on Form 8-K, as filed with the Commission on April 2, 2009 (File No. 001-16337)).
10.6**	—	Deferred Compensation Plan effective November 1, 2003 (incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, as filed with the Commission on March 5, 2004 (File No. 001-16337)).
10.7**	—	Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.8**	—	Executive Agreement between Oil States International, Inc. and Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.9**	—	Form of Change of Control Severance Plan for Selected Members of Management (incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1, as filed with the Commission on December 12, 2000 (File No. 333-43400)).
10.10	—	Credit Agreement, dated as of October 30, 2003, among Oil States International, Inc., the Lenders named therein and Wells Fargo Bank Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2003, as filed with the Commission on November 12, 2003 (File No. 001-16337)).
10.10A	—	Incremental Assumption Agreement, dated as of May 10, 2004, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12A to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2004, as filed with the Commission on August 4, 2004 (File No. 001-16337)).

10.10B	—	Amendment No. 1, dated as of January 31, 2005, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12B to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.10C	—	Amendment No. 2, dated as of December 5, 2006, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12C to the Company’s Current Report on Form 8-K, as filed with the SEC on December 8, 2006 (File No. 001-16337)).
10.10D	—	Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company’s Current Report on Form 8-K, as filed with the SEC on December 18, 2007 (File No. 001-16337)).
10.10E	—	Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company’s Current Report on Form 8-K, as filed with the Commission on October 2, 2009 (File No. 001-16337)).
10.10F	—	Amended and Restated Credit Agreement, dated as of December 10, 2010, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., as borrowers, the lenders named therein and Wells Fargo Bank, N.A., as Administrative Agent, U.S. Collateral Agent, the U.S. Swing Line Lender and an Issuing Bank; and Royal Bank of Canada, as Canadian Administrative Agent, Canadian Collateral Agent and the Canadian Swing Line Lender; JP Morgan Chase Bank, N.A., as Syndication Agent and Wells Fargo Securities, LLC, RBC Capital Markets and JP Morgan Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on December 20, 2010 (File No. 001-16337)).
10.10G	—	Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).
10.11**	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004 (File No. 001-16337)).

10.12**	—	Form of Director Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.13**	—	Form of Employee Non Qualified Stock Option Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.14**	—	Form of Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.15**	—	Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company’s Report on Form 8-K as filed with the Commission on November 15, 2006 (File No. 001-16337)).
10.16**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005 (File No. 001-16337)).
10.17**	—	Form of Non-Employee Director Restricted Stock Agreement under the Company’s 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.22 to the Company’s Report of Form 8-K, as filed with the Commission on May 24, 2005 (File No. 001-16337)).
10.18**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Bradley Dodson) effective October 10, 2006 (incorporated by reference to Exhibit 10.24 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, as filed with the Commission on November 3, 2006 (File No. 001-16337)).
10.19**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007 (incorporated by reference to Exhibit 10.25 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, as filed with the Commission on August 2, 2007 (File No. 001-16337)).
10.20**	—	Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009 (incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.21**	—	Amendment to the Executive Agreement of Bradley Dodson, effective January 1, 2009 (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.22**	—	Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009 (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

10.23**	—	Amendment to the Executive Agreement of Ron Green, effective January 1, 2009 (incorporated by reference to Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.24**	—	Amendment to the Executive Agreement of Robert Hampton, effective January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.25**	—	Executive Agreement between Oil States International, Inc. and named executive officer (Charles Moses), effective March 4, 2010 (incorporated by reference to Exhibit 10.26 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, as filed with the Commission on April 30, 2010 (File No. 001-16337)).
10.26**	—	Call Option Agreement, dated October 15, 2010, by and between Marley Holdings Pty Limited and PTI Holding Company 2 Pty Limited (incorporated by reference to Exhibit 10.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 5, 2010 (File No. 001-16337)).
10.27**	—	Assignment Letter between the Company and Ron Green effective May 3, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 6, 2011 (File No. 001-16337)).
21.1*	—	List of subsidiaries of the Company.
23.1*	—	Consent of Independent Registered Public Accounting Firm.
24.1*		Powers of Attorney for Directors.
31.1*		Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
31.2*		Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
32.1***		Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
32.2***		Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
101.INS***		XBRL Instance Document
101.SCH***		XBRL Taxonomy Extension Schema Document
101.CAL***		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	—	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB***		XBRL Taxonomy Extension Label Linkbase Document
101.PRE***		XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

** Management contracts or compensatory plans or arrangements

*** Furnished herewith.