Edgar Filing: OIL STATES INTERNATIONAL, INC

osii_10k-123112.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

/ / 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 [X] 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 [X]

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

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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 [X ] NO [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K. [X]

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 [X]	Accelerated filer [ ]

Non-accelerated filer [ ] (Do not check if a smaller reporting company)	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 [X]

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 29, 2012, was $3,341,802,313.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding as of February 19, 2013 was 54,873,460 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement for the 2013 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 Annual Report on Form 10-K, are incorporated by reference into Part III of this Annual Report on Form 10-K.

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TABLE OF CONTENTS

PART I		Page
Cautionary Statement Regarding Forward-Looking Statements		4
Item 1.	Business	5 – 22
Item 1A.	Risk Factors	22 – 37
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	38 – 39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39 – 42
Item 6.	Selected Financial Data	43 – 44
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	44 – 62
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63 – 64
Item 9B.	Other Information	65

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	65
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65

PART IV
Item 15.	Exhibits, Financial Statement Schedules	65 – 70
SIGNATURES		71
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		72

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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 known material factors that could affect our results, please refer to “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, 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," “proposed,” “should,” “seek,” and other similar words. All statements other than statements of historical facts contained in this Annual Report on Form 10-K, including statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions, are forward-looking statements. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.

In any forward-looking statement where we or our management express an expectation or belief as to the future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. Taking this into account, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our company;

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 the pace of recovery from the recent recession;

our ability to find and retain skilled personnel;

the availability and cost of capital; and

the other factors identified in “Part I, 1A. "Risks Factors."

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. 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, 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 “Oil States” 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 (the Board) documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company's Corporate Governance Guidelines, Code of Business Conduct and Ethics and Financial Code of Ethics for Senior Officers, 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 Annual Report on 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 make organic capital expenditures to enhance our cash flows and increase our shareholders’ returns. 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 over the last five years totaled approximately $1.5 billion and has included both growth and maintenance capital expenditures in each of our businesses. Capital spending totaled $1.2 billion over the period 2010 to 2012, 67% of which was spent in our accommodations segment.

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In addition to capital spending, we have spent $810 million over the period 2010 to 2012 for acquisitions of businesses. Acquisitions of other oilfield service and accommodations businesses have been an important aspect of our growth strategy and plan to increase shareholder value. Our acquisition 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 each of our business segments.

On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $48.3 million consisting of $32.5 million in cash and contingent consideration with a fair value of $15.8 million. The Company funded escrow accounts totaling $25.3 million related to the contingent consideration and seller transaction indemnities which are classified as “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for contingent consideration and escrowed amounts potentially due to the seller total $21.1 million at December 31, 2012 and are classified as “Other noncurrent liabilities” in our Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.

On July 2, 2012, we acquired all of the operating assets of Piper Valve Systems, Ltd (Piper) for total cash consideration of $48.0 million. Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects offshore (surface and subsea) and onshore. The operations of Piper have been included in our offshore products segment since the acquisition date.

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 provides 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 the acquisition date.

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 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 including estimated contingent consideration of $4.0 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 the acquisition date.

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 the acquisition date

The Company funded all of its acquisitions with cash on hand and/or amounts available 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.

Our Industry

We principally operate in the oilfield services industry and provide a broad range of products and services to our customers through each of our business segments. In our accommodations segment, we also support the mining industry in Australia. See Note 15 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 for each of the three years ended December 31, 2012, 2011 and 2010. 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.

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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 segment 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 resulting from the global financial crisis, activity in our accommodations business has grown significantly in the last six years.

The positive outlook for long-term oil demand, along with improvements in oil prices over the last two years have resulted in increased bidding and quoting activity for our offshore products since the latter part of 2010. As a result of this increased activity, backlog in our offshore products segment increased from $354 million at December 31, 2010 to $535 million as of December 31, 2011, and to a year-end record of $561 million as of December 31, 2012. We anticipate global deepwater spending to continue at robust levels due to new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico, Southeast Asia and Australia over the next twelve months.

Our well site services business segment is affected by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world. 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, considering 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 1,340 rigs, the highest oil-related rig count in over 20 years, comprising approximately 76% of total U.S. drilling activity.

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 oil country tubular goods (OCTG) manufacturing capacity, inventory and pricing. Historically, tubular services’ gross margins generally expand during periods of rising OCTG prices and contract during periods of decreasing OCTG prices. Our tubular services business segment has historically been our most cyclical business segment. Nonetheless, the strong U.S. land drilling activity in 2011 and 2012, along with the return of drilling in the U.S. Gulf of Mexico following the Macondo well blowout, has led to increased tubular services volumes and revenues. OCTG prices fell throughout 2012 and pricing pressures are expected to continue into 2013 due to strong import levels and increasing domestic capacity and production.

Accommodations

Overview

During the year ended December 31, 2012, we generated approximately 25% of our revenue and 50% 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 support workforces in the Canadian oil sands and in a variety of oil and natural gas drilling, mining and related natural resource applications as well as disaster relief efforts, primarily in Canada, Australia and the United States.

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Accommodations Market

Our accommodations business has grown 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.

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 and a major contributor to gross domestic product, employment and government revenue. The current activities of our Australian accommodations business are primarily related to supplying accommodations in support of metallurgical (met) 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. Economic growth in emerging economies, such as China and India, with associated demand for mineral and natural resources such as coal, iron ore and LNG, has more than offset more muted growth in the more developed economies including those of the United States, Japan and Europe. This commodity demand is expected to underpin continued investment and growth in the Australian natural resources market.

Products and Services

We believe our “Develop, Own, Operate” business model provides consistent service delivery to our customers and provides us a competitive advantage in our accommodations segment. Our integrated model includes site identification, permitting and development, facility design, construction, installation and full site maintenance. We provide a turnkey solution for our customers’ accommodation needs.

Since mid-year 2006, we have installed over 11,000 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. Our oil sands lodges support construction and operating personnel for maintenance and expansionary projects as well as ongoing operations associated with surface mining and in-situ oil sands projects generally under medium-term contracts (two to three years). During 2012, we added 1,125 rooms (net of retirements) to our major oil sands lodges by expanding our Athabasca, Beaver River, Henday and Conklin Lodges. Our Wapasu Creek Lodge is equivalent in size to the largest hotels in North America.

Our Australian accommodations business operates eight villages with over 8,600 rooms currently 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-lived, low-cost mines operated by large mining companies. During 2012, the Company added 1,305 rooms (net of retirements) to its Australian accommodations business by expanding existing villages and by constructing one new village, Karratha Village, our first village serving the northwest region of Australia.

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More than two-thirds of our accommodations revenue is generated by our large-scale lodge and village facilities. Total rooms deployed at our major Canadian oil sands lodges and Australian villages were as follows:

	December 31,
	2012		2011		2010
Canadian Oil Sands Lodges

Wapasu		5,174		5,174		4,013
Athabasca		1,877		1,776		1,537
Henday		1,698		1,120		-
Conklin		948		584		608
Beaver River		876		732		732
Lakeside		510		510		510
Other		10		72		83
Total Canadian Oil Sands Lodges		11,093		9,968		7,483

Australian Villages

Coppabella		2,912		2,556		1,654
Dysart		1,912		1,491		1,249
Moranbah		1,240		1,180		889
Middlemount		816		816		690
Narrabri		502		242		-
Nebo		490		490		490
Calliope		300		300		-
Kambalda		238		238		238
Karratha		208		-		-
Total Australian Villages		8,618		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 an 800-person camp supporting varied operations, including pipeline construction, Steam Assisted Gravity Drainage drilling operations and large shale oil projects.

With our integrated business model, our internal manufacturing capabilities allow us to respond quickly to changing customer needs and timing. 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 one in Johnstown, Colorado. Each of our facilities specializes 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 $1.1 billion, or 54%, of our total consolidated capital expenditures on our Canadian and Australian accommodations businesses.

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, 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.

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 2012 were Imperial Oil and Fluor Canada Ltd. in Canada and BHP Billiton Mitsubishi Alliance 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. and Clean Harbors, Inc. Our primary competitors in Australia include Cleary Norman JV, Ausco Modular Pty Limited, Fleetwood Corporation Limited, the Tribute Group and Auzcorp Pty Ltd. Accommodations are also sometimes owned and/or operated by our existing and potential customers. Management estimates that our existing and potential customers own approximately 50% of the rooms available in the Canadian oil sands and 60% of the rooms in the Australian coal mining regions.

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Offshore Products

Overview

During the year ended December 31, 2012, we generated approximately 18% of our revenue and 18% 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, high-pressure compact valves, deepwater mooring systems, cranes, subsea pipeline products, blow-out preventer stack integration, specialty welding services, offshore installation services and repair services. We have facilities that support our offshore products segment in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Oklahoma City and Tulsa, Oklahoma; Scotland; Brazil; England; Singapore, Thailand, Vietnam and India.

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 as well as 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 for these activities.

Products and Services

Celebrating 70 years of operations in 2012, 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 tension leg platforms, floating production, storage and offloading (FPSO) vessels, Spars, and on other marine vessels, floating rigs, vessels and jack-up rigs. Our products and services include:

flexible bearings and connector products;

casing and conductor connections and pipe;

subsea pipeline products;

high-pressure compact ball valves, manifold system components and diverter valves;

marine winches, mooring systems, cranes and rig equipment;

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 Advanced Connection Systems. We are a significant supplier of flexible bearings, or FlexJoint®, to the offshore oil and gas industry as well as weld-on connectors and fittings that join lengths of large diameter conductor or casing used in offshore drilling and production operations. A FlexJoint® is a flexible bearing that permits the controlled movement of riser pipes or tension leg platform tethers under high tension and pressure. A FlexJoint® or our flex element at the top, bottom and, in some cases, middle of a deepwater riser reduces the stress and tension on the riser compensating for the pitch and rotational forces on the riser as the production facility or drilling rig moves with ocean forces. 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. Our FlexJoint® bearings 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 natural gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. A tension leg platform (TLP) 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. An FPSO is a floating vessel, typically ship shaped, used to produce, and process oil and natural gas from subsea wells. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. Our FlexJoint® bearings are also used to attach the steel catenary risers to an FPSO, tension leg platform or Spar, and for use on import or export risers.

Our advanced connection systems provide connectors used in various drilling and production applications offshore. These connectors are welded onto pipe to provide more efficient joint to joint connections with enhanced tensile and burst capabilities that exceed those of connections that are cut into plain end pipe. Our connectors are reusable and pliable and in some cases provide metal-to-metal seals. We offer a suite of connectors offering differing specifications depending on the application. Our Merlin™ connectors are our premier connectors combining superior static strength and fatigue life with fast, non-rotational make-up and a slim profile. Merlin™ connectors have been used in sizes up to 60 inches (outside diameter) for applications including open-hole and tie-back casing, offshore conductor casing, pipeline risers and TLP tendons (which moor the TLP to the sea floor).

These flexible bearings and advanced connector systems are primarily manufactured through our Arlington, Texas, U.K. and Singapore locations.

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 and 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.

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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.

Our subsea pipeline products are primarily designed and manufactured at our two Houston, Texas manufacturing locations.

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. These products are primarily designed and manufactured at our Houma, Louisiana location.

BOP Stack Assembly, Integration, Testing and Repair Services. While we do not manufacture BOP stack assemblies, 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.

These assembly and testing services are offered through our Houston, Texas, U.K., Singapore and Brazil locations.

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 FlexJoint® bearings 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.

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Backlog. Backlog in our offshore products segment was $561 million at December 31, 2012, compared to $535 million at December 31, 2011 and $354 million at December 31, 2010. We expect in excess of 90% of our backlog at December 31, 2012 to be recognized as revenue during 2013. 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 natural 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 2012 were Chevron Corporation, Halliburton Company, and Royal Dutch Shell plc. Our main competitors include Cameron International Corporation, National Oilwell Varco, Inc., GE Oil & Gas, Liebherr Cranes, Inc., FMC Technologies, Inc. and Dril-Quip, Inc.

Well Site Services

Overview

During the year ended December 31, 2012, we generated approximately 16% of our revenue and 22% 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 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 completion tools and drilling rigs to serve our customers at well sites and project development locations. Our products and services are used primarily in onshore applications throughout the drilling, completion and production phases of a well's life.

Well Site Services Market

Demand for our completion services and drilling services 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.

Services

Completion Services. Our completion services business provides a wide range of services for use in the onshore and offshore oil and gas industry, including:

wireline and coiled tubing services;

wellhead isolation services;

well testing and flowback services, including separators and line heaters;

pipe recovery systems;

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thru-tubing milling and fishing services;

hydraulic chokes and manifolds;

blow out preventers;

downhole extended-reach technology;

gravel pack operations on well bores; and

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

Our completion services employees typically rig up and operate our equipment on the well site for our customers. Our well site equipment is primarily used during the completion and production stages of a well. As of December 31, 2012, we provided completion services at approximately 55 distribution points throughout the United States, Canada, Mexico and Argentina. 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 typically provide our services and equipment based on daily rates varying depending on the type of equipment and the length of time. Billings to our customers typically separate charges for our equipment from charges for our field technicians. We own patents or have patents pending covering some of our technology, particularly in our wellhead isolation equipment and downhole extended-reach technology product lines. Our customers in the completion services business include major, independent and private oil and gas companies and other large oilfield service companies. Our largest customers in 2012 were Anadarko Petroleum Corporation, Chesapeake Energy Corporation and Devon Energy Corporation. Competition in the completion services business is widespread and includes many smaller companies, although we also compete with the larger oilfield service companies for certain products and services.

Drilling Services. Our drilling services business, which is marketed through the brand of Capstar Drilling, our wholly-owned subsidiary, 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, 2012, after losing one of our rigs in the Rockies to fire in February 2012, we had a total of thirty-three semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds, fourteen of which were fabricated and/or assembled in our Odessa, Texas facility with components purchased from specialty vendors during the last nine years. Twenty-five of these drilling rigs are based in Odessa, Texas and eight are based in the Rocky Mountain region. Utilization of our drilling rigs increased from an average of 82% in 2011 to an average of 88% in 2012. On December 31, 2012, twenty-seven of our rigs, or 82%, were working or under contract.

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 a footage and a 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 2012 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.

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Tubular Services

Overview

During the year ended December 31, 2012, we generated approximately 41% of our revenue and 10% 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, third-party inspection and 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 2012, 81% 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. The OCTG Situation Report suggests that industry OCTG inventory levels have increased throughout 2012 and currently stand at five to six months' supply. 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 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.

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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 389 acres and has more than 860 pipe racks. Our Godley, Texas facility, which services the Barnett shale area, has approximately 330 pipe racks on approximately 31 acres and is serviced by a rail spur. Our Searcy location, which services the Fayetteville shale area, has approximately 110 pipe racks on 14 acres. Our Montoursville, Pennsylvania location, which services the Marcellus shale area, has more than 220 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 alliances and spot market sales. We provide a large portion 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 alliance arrangements 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 and, therefore, generate reliable returns on investment. At December 31, 2012, approximately 87% of our OCTG inventory was supported by customer orders.

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 2012 were Chesapeake Energy Corporation, Occidental Petroleum Corporation and Chevron 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, by Hurricane Ike.

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Employees

As of December 31, 2012, the Company had 8,716 full-time employees on a consolidated basis, 43% of whom are in our accommodations segment, 28% of whom are in our well site services segment, 26% 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 2,299 employees located in Canada, Australia, the United Kingdom and Argentina as of December 31, 2012. We believe we have healthy labor relations with our employees.

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, 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 the extent to which new laws and regulations will be adopted or whether such new laws and regulations may impose more stringent or costly restrictions on our operations.

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 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 areas where we operate 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 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 yet critical. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with existing environmental laws and regulations and we do not anticipate that future compliance with existing environmental laws and regulations will have a material effect on our Consolidated Financial Statements. However, there can be no assurance that substantial costs for compliance or penalties for non-compliance with these existing requirements will not be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities that we cannot currently quantify.

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 specific to the oil sands with respect to water, air quality and biodiversity. 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. In 2012, the governments of Canada and Alberta released the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring that will be phased in between 2012 and 2015. The costs of implementing this plan are to be funded by industry.

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As this new monitoring regime is implemented, the increased levels of monitoring and enforcement may increase costs for us and our customers and reduce activity and demand for our services.

Further, the Province of Alberta released its new Clean Air Strategy in October 2012 which it proposes to implement beginning in 2013. The implementation of this strategy along with Alberta’s continued implementation of its regulatory changes to oil and oil sands regulation 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. Drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. It is possible that certain of these oil and natural gas exploration and production wastes now classified as non-hazardous could be re-classified as hazardous in the future. Any such re-classification of these currently exempt wastes to hazardous could subject us to more rigorous and costly operating and disposal requirements, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we also generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes.

Also in connection with our U.S. operations, 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 disposal site where the release occurred and companies that transported, disposed of, or arranged for the transport or 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 have been conducted by previous owners or operators 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.

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 or operated by us have been used for oil and natural 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 developed 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 under OPA includes the owner or operator of an onshore 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, require the development and implementation of spill prevention and response plans and impose potential liability for the remedial costs and associated damages arising out of any unauthorized discharges.

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A certain portion of our completion 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 fracturing fluids disposal on drinking water and 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 fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. 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, some states have adopted and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state or local 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 completion services and tubular services businesses.

In addition, certain domestic governmental reviews have been conducted or are underway 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 the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review 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 (DOE) and the U.S. Department of the Interior (DOI), have evaluated or 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.

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Following an April 30, 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third-party in ultra-deep water in the U.S. Gulf of Mexico, there have been a series of regulatory initiatives developed and implemented at the federal level to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2012, the U.S. Department of the Interior, or DOI, through a series of inter-agencies that have since evolved into the present day Bureau of Ocean Energy Management, or BOEM, and Bureau of Safety and Environmental Enforcement, or BSEE, have issued a variety of regulations and Notices to Lessees and Operators, or NTLs, intended to impose additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and production operations in the U.S. Gulf of Mexico as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present day bureaus. Under the DOI’s current inter-agency format, the BOEM administers offshore leasing, resource evaluation, oil and natural gas exploration and production plan reviews, renewable energy development, National Environmental Policy Act analyses, and environmental studies whereas the BSEE manages responsibility for the safety and enforcement functions imposed on offshore oil and natural 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 compliance programing and training. Offshore oil and natural gas exploration and production operators, including some that are our customers, are required to comply with this more stringent and comprehensive array of legal requirements as conditions to initiating and/or continuing offshore activities in the U.S. Gulf of Mexico, compliance with which has made it more difficult and costly for these operators in proceeding with those activities and more prone to potential delays, whether due to permit delays, the aggregate effect of more regulation, the need for new or retrofitted equipment or processes or qualified personnel, or otherwise. In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, 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 OPA. If the regulatory initiatives implemented and pursued over the past few years or the threat of added restrictions, whether through legislative or regulatory means or increased or broadened enforcement programs, foster uncertainties or delays in offshore oil and natural gas development or exploration activities, then such conditions would be viewed by us as having an overall negative effect on those offshore activities 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 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 August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013.

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. 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.

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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 business is regulated by general statutory environmental controls at both the state and federal level which may result in land use approval and compliance risk. These controls include: land use and urban design controls; the regulation of hard and liquid waste, including the requirement for tradewaste and/or wastewater permits or licenses; the regulation of water, noise, heat, and 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 and energy efficiency 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”) commenced 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.

The EPA determined in December 2009 that emissions of GHGs present an endangerment to public health and the environment and, based on those findings, 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.

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While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and natural gas, which could reduce the demand for the oil and natural gas that we help produce. 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, 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 in 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA before the end of 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.

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Our business is subject to a number of economic risks.

Financial markets worldwide experienced extreme disruption in the past five 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;

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 for both oil and natural gas, 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;

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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 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 or natural gas 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 regarding potential impacts of hydraulic fracturing and fracturing fluids disposal on drinking water and 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 fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. 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, some states have adopted and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular.

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In addition, certain domestic governmental reviews have been conducted or are underway 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 the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review 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 DOE and the DOI, have evaluated or 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 operators, some of which are our customers, and thus reduce demand for our North American completion products and services. In the event that new or more stringent federal, state or local 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 the products and services of each of our business segments.

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 clients 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 accommodations 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;

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

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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 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, then 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 which may adversely affect our results of operations.

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;

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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 which may, in turn, result in termination of accommodation supply contracts;

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 in the U.S. Gulf of Mexico.

In the aftermath of the Macondo well incident in April 2010, there have been a series of regulatory initiatives developed and implemented at the federal level to address the direct impact of the incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2012, the DOI, through a series of inter-agencies that have since evolved into the present day Bureau of Ocean Energy Management, or BOEM, and Bureau of Safety and Environmental Enforcement, or BSEE, issued a variety of regulations and Notices to Lessees and Operators, or NTLs, intended to impose additional safety, permitting and certification requirements applicable to exploration, development and production activities in the U.S. Gulf of Mexico. These regulatory initiatives effectively slowed down the pace of drilling and production operations in the U.S. Gulf of Mexico as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present day bureaus. Offshore oil and natural gas exploration and production operators, including some that are our customers, are required to comply with this more stringent and comprehensive array of legal requirements as conditions to initiating and/or continuing offshore activities in the U.S. Gulf of Mexico, compliance with which has made it more difficult and costly for these operators in proceeding with those activities and more prone to potential delays, whether due to permit delays, the aggregate effect of more regulation, the need for new or retrofitted equipment or processes or qualified personnel, or otherwise. In addition, governmental officials responsible for one or more of the aforementioned regulatory bodies have publically stated that their authority extends beyond oil and gas operators to include service and equipment contractors as well. This governmental assertion of broad legal authority to govern contractors’ activity is a new development, may be subject to future clarification and may result in the development and implementation of various regulatory compliance programs governing contractor activities. We are uncertain about the potential breadth of future regulatory initiatives, if implemented, or the specific responsibilities that may arise from these initiatives, but expect that the implementation of new or more stringent initiatives may subject us and other contractors to increased costs and liabilities to comply, which could have a significant adverse effect on our operations. We believe that offshore contractors and service providers, including ourselves, will closely monitor rulemaking in this area to ensure ongoing compliance.

In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, 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 OPA. If the regulatory initiatives implemented and pursued over the past few years or the threat of added restrictions, whether through legislative or regulatory means or increased or broadened enforcement programs, foster uncertainties or delays in offshore oil and natural gas development or exploration activities, then such conditions would be viewed by us as having an overall negative effect on those offshore activities and, to a certain extent, our financial results.

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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 oil sands region of Alberta, Canada and in the coal producing 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, 2012, goodwill represented approximately 12% 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 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 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 completion 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; or

valuations for comparable public companies or comparable acquisition valuations deteriorate.

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.

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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 31% (15% excluding Canada; 9% excluding Canada and Australia) of our consolidated revenue in the year ended December 31, 2012. Risks associated with our operations in foreign areas include, but are not limited to:

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expropriation, confiscation or nationalization of assets;

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renegotiation or nullification of existing contracts;

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foreign exchange restrictions;

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foreign currency fluctuations;

•

foreign taxation;

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the inability to repatriate earnings or capital;

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changing political conditions;

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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

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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 in such jurisdictions.

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.

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Exchange rate fluctuations could adversely affect our results of operations and financial position.

In the ordinary course of our business, we enter into purchase and sales commitments that are denominated in currencies that differ from the functional currency used by our operating subsidiaries. Currency exchange rate fluctuations can create volatility in our consolidated financial position, results of operations and/or cash flows. Although we may enter into foreign exchange agreements with financial institutions in order to reduce our exposure to fluctuations in currency exchange rates, these transactions, if entered into, will not eliminate that risk entirely. To the extent that we are unable to match sales received in foreign currencies with expenses paid in the same currency, exchange rate fluctuations could have a negative impact on our consolidated financial position, results of operations and/or cash flows. Additionally, because our consolidated financial results are reported in U.S. dollars, if we generate net sales or earnings within entities whose functional currency is not the U.S. dollar, the translation of such amounts into U.S. dollars can result in an increase or decrease in the amount of our net sales and earnings depending upon exchange rate movements. With respect to our potential exposure to foreign currency fluctuations and devaluations, for the year ended December 31, 2012, approximately 31% of our sales originated from subsidiaries outside of the U.S. in currencies including, among others, the Canadian dollar, the Australian dollar and the pound sterling. As a result, a material decrease in the value of these currencies relative to the U.S. dollar may have a negative impact on our reported sales, net income and cash flows. Any currency controls implemented by local monetary authorities in countries where we currently operate could also adversely affect our business, financial condition and results of operations.

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 liabilities 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, 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.

An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.

There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons, because of air emissions and waste water discharges related to our operations, and due to historical industry operations and waste disposal practices. Certain environmental statutes impose joint and several, strict liability for these costs. For example, an accidental release by us in the performance of well site services at one of our customers’ sites could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover some or any of these costs from insurance.

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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 any 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. Significant focus is being made on companies that are active producers of depleting natural resources.

There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of foreign, U.S. federal, regional, provincial and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:

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 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 "Part I, Item 1. “Business - 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 by increasing the costs of doing business and decreasing the demand for our products.

The current U.S. administration and Congress have proposed several new articles of legislation or legislative and administrative 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;

increased 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.

- 31 -

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 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, by Hurricane Ike.

We are exposed to risks 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 that we may acquire, 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;

- 32 -

•

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;

•

increased logistical problems common to large, expansive operations; and

•

inability to pursue and protect patents covering acquired technology.

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 amounts 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.

- 33 -

We depend on several significant customers in each of our business segments, and the loss of one or more such customers or the inability of one or more such customers to meet their obligations to us could adversely affect our results of operations.

We depend on several significant customers in each of our business segments. The majority of our customers operate in the energy or mining industry. For a more detailed explanation of our customers for each of our business segments, see “Item 1. Business.” The loss of any one of our largest customers in any of our business segments or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations. In addition, the 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. While we perform ongoing credit evaluations of our customers, we do not generally require collateral in support of our trade receivables. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our common stock price has been volatile, and we expect it to continue to remain volatile in the future.

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 (2012 low of $61.28 per share; 2012 high of $86.65 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 risks in developing, manufacturing and delivering products in our offshore products business segment.

Many of our products from our offshore products segment are ordered by customers under frame agreements or project specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. In addition, some customer contracts stipulate consequential damages payable, generally as a result of our gross negligence or willful misconduct. The final delivered products may also include customer and third-party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.

In certain cases these orders include new technology or unspecified design elements. In some cases we may not be fully or properly compensated for the cost to develop and design the final products, negatively impacting our profitability on the projects. In addition, our customers, in many cases, request changes to the original design or bid specifications for which we may not be fully or properly compensated.

As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs and any gross profit realized on these fixed-price contracts may vary from the initially expected contract economics. There is inherent risk in the estimation process 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-of-completion accounting, depending on the size and length 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.

- 34 -

Backlog in our offshore products segment 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 businesses 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 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 unable 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 completion services business, become the less attractive solution, our operations and profitability would be negatively impacted.

- 35 -

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 2012, 81% 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 these 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 completion services 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 seven years and in Australia over the past two years 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.

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 completion services businesses, particularly our patents relating to our FlexJoint® and Merlin™ technology and intervention and downhole extended-reach 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.

- 36 -

Loss of key members of our management could adversely affect our business.

We depend on the continued employment and performance of key members of our 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 risks 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 an economic downturn, commodity prices typically decline, and the credit markets and availability of credit can be expected to be constrained. Additionally, many of our customers’ equity values could decline. 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.

As of December 31, 2012, we are party to collective bargaining agreements covering 1,692 employees in Canada, 574 employees in Australia, 17 employees in Argentina and 16 employees in the United Kingdom. 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.

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 our 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)	41 acres	Various contiguous offices, 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
Tulsa, Oklahoma	74,600	Molding facility for offshore products
Tulsa, Oklahoma (lease)	14,000	Molding facility for offshore products
Oklahoma City, Oklahoma	70,000	Offshore products service facility and office
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	389 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
Vernal, Utah (lease)	21 acres	Accommodations facility and yard
Carrizo Springs, Texas (lease)	20 acres	Accommodations facility
Johnstown, Colorado	13 acres	Accommodations manufacturing facility and yard
Belle Chasse, Louisiana (own and lease)	10 acres	Accommodations manufacturing facility and yard
Three Rivers, Texas (lease)	9 acres	Accommodations facility
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
Houston, Texas	23,441	Completion services office
Midland, Texas	11 acres	Completion services shop
Houma, Louisiana	10 acres	Completion services shop
Rock Springs, Wyoming	10 acres	Completion services shop
Conway, Arkansas	7 acres	Completion services shop
Oklahoma City, Oklahoma	3 acres	Completion services shop
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
Nisku, Alberta	9 acres	Accommodations manufacturing facility
Edmonton, Alberta (lease)	86,376	Accommodations office and warehouse
Edmonton, Alberta (lease)	28,253	Accommodations office
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:
Coppabella, Queensland, Australia	198 acres	Accommodations facility
Calliope, Queensland, Australia	124 acres	Accommodations facility
Narrabri, New South Wales, Australia	82 acres	Accommodations facility
Dysart, Queensland, Australia	50 acres	Accommodations facility
Middlemount, Queensland, Australia	37 acres	Accommodations facility
Karratha, Western Australia, Australia (lease)	34 acres	Accommodations facility
Kambalda, Western Australia, Australia	27 acres	Accommodations facility
Nebo, Queensland, Australia	26 acres	Accommodations facility
Moranbah, Queensland, Australia	17 acres	Accommodations facility
Ormeau, Queensland, Australia (lease)	3 acres	Accommodations manufacturing facility
Yatala, Queensland, Australia (lease)	2 acres	Accommodations manufacturing facility
Sydney, New South Wales, Australia (lease)	17,276	Accommodations office
Brisbane, Queensland, Australia (lease)	7,115	Accommodations office

Other International:
Aberdeen, Scotland (lease)	15 acres	Offshore products manufacturing facility and yard
Rio de Janeiro, Brazil	31 acres	Offshore products manufacturing facility and yard
Macaé, Brazil	17 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
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 have eight tubular sales offices and a total of 55 completion services locations throughout the United States and in 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.

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 54,873,460 shares of common stock outstanding as of February 19, 2013. The approximate number of record holders of our common stock as of February 19, 2012 was 27. 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 19, 2013 was $80.25 per share.

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

	Sales Price
	High		Low
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
2012
First Quarter	$	87.65	$	75.17
Second Quarter		82.83		60.03
Third Quarter		87.63		65.17
Fourth Quarter		80.46		63.42

We have not declared or paid any cash dividends on our common stock since our IPO 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 Operation.” 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, 2007 to December 31, 2012. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2007 and assume the reinvestment of all dividends.

Oil States International – NYSE

	Cumulative Total Return
		12/07		12/08		12/09		12/10		12/11		12/12
OIL STATES INTERNATIONAL, INC.	$	100.00	$	54.78	$	115.15	$	187.84	$	223.83	$	209.67
S & P 500		100.00		63.00		79.67		91.67		93.61		108.59
PHLX OIL SERVICE SECTOR (OSX)		100.00		40.95		67.83		82.91		70.00		71.39

*$100 invested on December 31, 2007 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.

- 41 -

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Purchases of Equity Securities by the Issuer and Affiliated Purchases

Period	Total Number of Shares Purchased			Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Program		Approximate Dollar Value of Shares That May Yet Be Purchased Under the Program (1)
October 1, 2012 – October 31, 2012		583	(2)	$	76.52	(3)		--	$	200,000,000
November 1, 2012 – November 30, 2012		146,494	(4)	$	66.53	(5)		146,396	$	190,260,656
December 1, 2012 - December 31, 2012		79,400		$	69.34	(6)		79,400	$	184,754,796
Total		226,477		$	67.54			225,796	$	184,754,796

(1)

On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization, which was set to expire on September 1, 2012. The current share repurchase program expires on September 1, 2014.

(2)

Shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(3)

The price paid per share was based on the weighted average closing price of our Company’s common stock on October 4, 2012 and October 5, 2012, which represent the dates the restrictions lapsed on such shares.

(4)

Included in these shares are 98 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.

(5)

The price paid per share was based (a) on the dates in which we repurchased shares under our common stock repurchase program, and (b) on the weighted average closing price of our Company’s common stock on November 3, 2012, which represents the date the restrictions lapsed on such shares.

(6)

The price paid per share was based on the weighted average closing price of our Company’s common stock on the date in which we repurchased shares under our common stock repurchase program.

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Item 6. Selected Financial Data

The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2012. 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 Consolidated 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,
	2012			2011			2010			2009			2008
Statement of Income Data:
Revenues	$	4,413,088		$	3,479,180		$	2,411,984		$	2,108,250		$	2,948,457
Costs and Expenses:
Product costs, service and other costs		3,292,969			2,599,267			1,874,294			1,640,198			2,234,974
Selling, general and administrative expenses		203,651			182,434			150,865			139,293			143,080
Depreciation and amortization expense		230,098			188,147			124,202			118,108			102,604
Impairment of goodwill		--			--			--			94,528			85,630
Other operating (income) expense		2,590			1,809			7,041			(2,606	)		(1,586	)
Operating income		683,780			507,523			255,582			118,729			383,755
Interest expense, net of capitalized interest		(68,922	)		(57,506	)		(16,274	)		(15,266	)		(23,585	)
Interest income		1,583			1,700			751			380			3,561
Equity in earnings (loss) of unconsolidated affiliates		243			(163	)		239			1,452			4,035
Other income		10,211			3,515			330			414			5,684
Income before income taxes		626,895			455,069			240,628			105,709			373,450
Income tax provision(1)		(177,047	)		(131,647	)		(72,023	)		(46,097	)		(154,151	)
Net income	$	449,848		$	323,422		$	168,605		$	59,612		$	219,299
Less: Net income attributable to noncontrolling interest		1,239			969			587			498			446

Net income attributable to Oil States International, Inc.	$	448,609		$	322,453		$	168,018		$	59,114		$	218,853

Net income per share attributable to Oil States International, Inc:
Basic	$	8.47		$	6.30		$	3.34		$	1.19		$	4.41
Diluted	$	8.10		$	5.86		$	3.19		$	1.18		$	4.26
Average common shares outstanding
Basic		52,959			51,163			50,238			49,625			49,622
Diluted		55,384			55,007			52,700			50,219			51,414

	Year Ended December 31,
	2012			2011			2010			2009			2008

Other Data:
EBITDA, as defined(2)	$	923,093		$	698,053		$	379,766		$	238,205		$	495,632
Capital expenditures, including capitalized interest		487,937			487,482			182,207			124,488			247,384
Acquisitions of businesses, net of cash acquired(3)		80,449			2,412			709,575			(18	)		29,835
Net cash provided by operating activities		637,483			215,913			230,922			453,362			257,464
Net cash used in investing activities, including capital expenditures(3)		(576,977	)		(488,955	)		(889,680	)		(102,608	)		(246,094	)
Net cash provided by (used in) financing activities		120,558			257,888			649,032			(296,773	)		(1,666	)

	At December 31,
	2012		2011		2010		2009		2008
Balance Sheet Data:
Cash and cash equivalents	$	253,172	$	71,721	$	96,350	$	89,742	$	30,199
Total current assets		1,826,092		1,489,659		1,100,004		925,568		1,237,484
Property, plant and equipment, net		1,852,126		1,557,088		1,252,657		749,601		695,338
Total assets		4,439,962		3,703,641		3,015,999		1,932,386		2,298,518
Long-term debt and capital leases, excluding current portion and 2 3/8% Notes		1,279,805		971,621		731,732		8,215		299,948
2 3/8% contingent convertible senior subordinated notes		--		170,884		163,108		155,859		149,110
Total stockholders' equity		2,465,800		1,963,272		1,628,933		1,382,066		1,235,541

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

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(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.

(3)	On December 30, 2010, we acquired all of the ordinary shares of The MAC for a total purchase price of $638.0 million, net of cash acquired.

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,
	2012		2011		2010		2009		2008
Net income attributable to Oil States International, Inc.	$	448,609	$	322,453	$	168,018	$	59,114	$	218,853
Depreciation and amortization expense		230,098		188,147		124,202		118,108		102,604
Interest expense, net		67,339		55,806		15,523		14,886		20,024
Income tax provision		177,047		131,647		72,023		46,097		154,151
EBITDA, as defined	$	923,093	$	698,053	$	379,766	$	238,205	$	495,632

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

This Item 7 contains “forward-looking statements” - within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act 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

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, met coal and other mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is highly sensitive to current and expected commodity prices, principally that of crude oil, met coal and, to a lesser extent, natural gas.

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In the past few years, crude oil prices have been volatile due to global economic movements and uncertainties including regional take-away capacity. In the first quarter of 2012, the price of West Texas Intermediates (WTI) crude oil increased from a monthly average price of $100 per barrel in January to $106 per barrel in March as positive economic news related to growth rates projected in China and other emerging markets, consumer spending and U.S. consumer confidence indicating that an economic recovery was underway. In addition, prices increased in response to tensions in the Middle East region which caused fears of supply disruption. However, crude oil prices came under pressure during the second quarter of 2012 due to increased crude oil inventories, insufficient take-away capacity in Cushing, Oklahoma, higher output expectations amid new technology and lower economic growth forecasts. In addition, certain regional markets such as the Bakken, Permian Basin and Eagle Ford were negatively impacted by significant discounts to WTI due to insufficient pipeline and rail take-away capacity. The spot price of WTI crude oil decreased to as low as $78 per barrel in the second quarter of 2012. Since the end of the second quarter of 2012, the spot price of crude oil has substantially recovered and, as of February 19, 2013, is trading at approximately $97 per barrel for WTI crude and approximately $118 per barrel for Intercontinental Exchange (ICE) Brent crude. If the global supply of oil and global inventory levels continue to decrease due to government instability in many oil-producing nations and energy demand continues to increase in countries such as China, India and the U.S., we could see continued and/or additional increases in WTI oil prices which could positively affect future U.S. drilling activity. In Canada, Western Canadian Select (WCS), which is the crude price that many of our oil sands accommodations customers receive, traded at a discount to WTI that ranged from $7.25 to $42.50 per barrel during 2012. The WCS discount was primarily due to increasing crude production from the Canadian oil sands region coupled with limited pipeline and rail capacity to transport the oil sands crude to heavy oil refineries either in the U.S. or Canada. This WCS discount had and is likely to continue to have a negative impact on our oil sands customers’ desire to invest in increased oil sands production. As of February 19, 2013, WCS is trading at a discount to WTI of $25.00.

In spite of WTI’s recovery to over $90 per barrel late in 2012 and in the first quarter of 2013, there remains a risk that crude prices deteriorate going forward due to potentially slowing growth rates in China, 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. Recent WTI and Brent crude pricing trends are as follows:

	Average Price (per bbl)(1)
Quarter ended	WTI		Brent Crude		Western Canadian Select
12/31/2012	$	88.01	$	110.15	$	61.34
9/30/2012		92.17		109.63		76.75
6/30/2012		93.38		108.90		73.53
3/31/2012		102.85		118.54		75.82
12/31/2011		94.03		109.31		81.56
9/30/2011		89.71		112.47		75.05
6/30/2011		102.51		117.12		84.72
3/31/2011		93.93		104.90		72.43
12/31/2010		85.10		86.80		69.07
9/30/2010		76.01		76.41		57.08

(1) Source: WTI and Brent prices from U.S. Energy Information Administration (EIA) and WCS prices from Bloomberg.

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Due to significant over-supply of natural gas stemming from increased production from shale plays, natural gas prices fell precipitously in the fourth quarter of 2011 and the first half of 2012, reaching a low of $1.82 in April 2012. Since these lows, prices for natural gas in the United States improved subsequent to April 2012, largely due to increased demand for natural gas for electrical power generation and switching from coal to gas, but continue to be weak due to the rise in production from unconventional natural gas resources in North America, specifically onshore shale production, resulting from the broad application of horizontal drilling and hydraulic fracturing techniques. Natural gas prices are trading at approximately $3.30 per Mcf as of February 19, 2013. In addition, a considerable amount of natural gas is being derived as a by-product of drilling crude oil and natural gas liquids-oriented wells in liquids rich onshore basins. As a result, the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 430 rigs as of February 19, 2013. Although still overstocked, natural gas inventories in the U.S. have declined from 60% above the 5-year average as of the end of the first quarter of 2012 to only 12% above the 5-year average as of the end of 2012. Any increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, could constrain prices for natural gas for an extended period and result in fewer rigs drilling for gas in the near-term. Recent natural gas pricing trends are as follows:

Quarter ended	Natural Gas Average Price(1) (per mcf)
12/31/2012	$	3.40
9/30/2012		2.88
6/30/2012		2.29
3/31/2012		2.44
12/31/2011		3.32
9/30/2011		4.12
6/30/2011		4.37
3/31/2011		4.18
12/31/2010		3.81
9/30/2010		4.28

(1) Source: natural gas prices from EIA.

Chinese steel production growth has fallen this year as European economies have contracted and U.S. economic growth has been anemic, lowering demand for steel and steel inputs such as met coal and iron ore. As a result, prices for met coal and iron ore fell throughout 2012, but appear to have stabilized at current levels. Met coal prices have decreased from over $200/metric ton at the beginning of 2012 to approximately $160/metric ton at the end of 2012. Depressed met coal prices have led to some coal mine closures as well as delays in the start-up of some coal mining projects in Australia.

Various oil and gas industry analysts have projected increased 2013 global exploration and production expenditures compared to 2012. North American capital spending plans are likely to be lower year-over-year and are expected to be focused in oil-related onshore shale areas while international exploration and production budgets are expected to increase and primarily be spent on offshore projects.

Overview

Demand for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, demand 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 U.S. 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 ten years to in excess of thirty years and, consequently, these investments are dependent on those customers' longer-term view of commodity demand and prices. Oil sands development activity has increased over the past several years 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. For example, in the third quarter of 2012, we were awarded a ten-year contract in support of future operations personnel working on the Kearl Project, one of the Canadian oil sands potentially largest mining operations. In addition, several major and national oil companies have announced acquisitions and joint ventures to develop oil sands leases or other acquisitions of oil sands exposure that should bode well for future oil sands investment and, as a result, demand for oil sands accommodations. With the WCS discount to WTI, several oil sands customers have announced the deferral of new oil sands projects, which could negatively affect our ability to expand our oil sands room count or our occupancy levels.

We are expanding our Australian accommodations capacity to meet increasing demand, notably in the Bowen Basin in Queensland and in the Gunnedah and Hunter basins in New South Wales to support coal production, and in Western Australia to support LNG and other energy-related projects. Accommodations deployed to support onshore U.S. drilling activity in several of the active shale play regions have also favorably contributed to our results.

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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 completion services and, to a lesser extent, land drilling services. Our completion services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the completion 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 of West Texas, where we primarily drill oil wells, and the Rocky Mountain area in the U.S., where we drill both liquids-rich 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 the United States. 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.

We have a diversified product and service offering, which has led to exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services, land drilling and completion 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,
	2012		2011		2010		2009		2008
U.S. Land – Oil		1,335		966		573		270		377
U.S. Land - Natural gas and other		537		877		937		772		1,436
U.S. Offshore		47		32		31		44		65
Total U.S.		1,919		1,875		1,541		1,086		1,878
Canada		365		423		351		221		379
Total North America		2,284		2,298		1,892		1,307		2,257

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, 2012 decreased by fourteen rigs, or less than 1%, compared to the average for the year ended December 31, 2011 largely due to a decline in natural gas drilling partially offset by growth in the U.S. land oil rig count.

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, since 2011, Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. For the year ended December 31, 2012, average U.S. dollar and Canadian and Australian dollar exchange rates were comparable with a less than 1% change over average exchange rates in 2011.

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 OCTG 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.

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During 2011 and 2012, OCTG marketplace supply and demand became more balanced compared to the previous two years. Increased supplies of OCTG have met the increased demand created by expanded drilling activity. Throughout 2011 and 2012, imports of OCTG have increased, particularly goods imported from Canada and Korea followed by India, Mexico and Japan. Additionally, domestic OCTG mill capacity increased in 2012. These increases in supply have been in response to increased well complexity coupled with the 2% year-over-year increase in the drilling rig count in the U.S. The OCTG Situation Report suggests that industry OCTG inventory levels have increased throughout 2012 and currently stand at five to six months' supply. Ample industry inventory on the ground along with increasing imports and domestic production coupled with modestly declining drilling activity put downward pressure on OCTG prices throughout 2012. Average OCTG prices declined 9% during 2012.

We remain focused on working capital management and generating returns on invested capital 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.

Although higher than 2011, the drilling rig count in 2012 in the U.S. Gulf of Mexico remains below historical levels following the April 2010 Macondo well incident and resultant oil spill in the U.S. Gulf of Mexico. Beginning in the third quarter of 2011, however, U.S. Gulf of Mexico drilling activity has shown signs of a slow but steady, recovery as permitting levels have improved. New well permitting has increased from 109 permits issued in 2011 to 179 permits issued in 2012.

We continue to monitor the global economy, the demand for crude oil, met 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 2012 totaled $488 million compared to 2011 capital expenditures of $487 million. Our 2012 capital expenditures included funding to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total 2012 capital expenditures were 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 an evaluation of both the market outlook and industry fundamentals. We currently expect to spend a total of approximately $600 million to $650 million for capital expenditures during 2013.

Recent Acquisitions

On December 14, 2012, we acquired all of the equity of Tempress for purchase price consideration of $48.3 million consisting of $32.5 million of cash and contingent consideration with a fair value of $15.8 million. The Company funded escrow accounts totaling $25.3 million related to the contingent consideration and seller transaction indemnities which are classified as “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for contingent consideration and escrowed amounts potentially due to the seller total $21.1 million at December 31, 2012 and are classified as “Other noncurrent liabilities” in our Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.

On July 2, 2012, we acquired all of the operating assets of Piper for total cash consideration of $48.0 million. Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects located offshore (both surface and subsea) and onshore. The operations of Piper have been included in our offshore products segment since the acquisition date.

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On December 30, 2010, we acquired all of the ordinary shares of 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 for total consideration of $47.1 million including estimated contingent consideration of $4.0 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 the acquisition date.

On October 5, 2010, we purchased all of the equity of 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.

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Consolidated Results of Operations (in millions)

	YEARS ENDED December 31,
							Variance 2012 vs. 2011					Variance 2011 vs. 2010
	2012			2011			$		%			2010			$		%
Revenues
Well site services -
Completion services	$	522.6		$	488.0		$	34.6		7	%	$	343.0		$	145.0		42	%
Drilling services		191.0			165.9			25.1		15	%		133.2			32.7		25	%
Total well site services		713.6			653.9			59.7		9	%		476.2			177.7		37	%
Accommodations		1,113.5			864.7			248.8		29	%		537.7			327.0		61	%
Offshore products		804.1			585.8			218.3		37	%		428.9			156.9		37	%
Tubular services		1,781.9			1,374.8			407.1		30	%		969.2			405.6		42	%
Total	$	4,413.1		$	3,479.2		$	933.9		27	%	$	2,412.0		$	1,067.2		44	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Completion services	$	324.6		$	298.4		$	26.2		9	%	$	220.1		$	78.3		36	%
Drilling services		133.2			122.7			10.5		9	%		105.5			17.2		16	%
Total well site services		457.8			421.1			36.7		9	%		325.6			95.5		29	%
Accommodations		552.3			456.4			95.9		21	%		314.4			142.0		45	%
Offshore products		595.9			430.0			165.9		39	%		316.5			113.5		36	%
Tubular services		1,687.0			1,291.8			395.2		31	%		917.8			374.0		41	%
Total	$	3,293.0		$	2,599.3		$	693.7		27	%	$	1,874.3		$	725.0		39	%
Gross margin
Well site services -
Completion services	$	198.0		$	189.6		$	8.4		4	%	$	122.9		$	66.7		54	%
Drilling services		57.8			43.2			14.6		34	%		27.7			15.5		56	%
Total well site services		255.8			232.8			23.0		10	%		150.6			82.2		55	%
Accommodations		561.2			408.3			152.9		37	%		223.3			185.0		83	%
Offshore products		208.2			155.8			52.4		34	%		112.4			43.4		39	%
Tubular services		94.9			83.0			11.9		14	%		51.4			31.6		61	%
Total	$	1,120.1		$	879.9		$	240.2		27	%	$	537.7		$	342.2		64	%
Gross margin as a percentage of revenues
Well site services -
Completion services		38	%		39	%							36	%
Drilling services		30	%		26	%							21	%
Total well site services		36	%		36	%							32	%
Accommodations		50	%		47	%							42	%
Offshore products		26	%		27	%							26	%
Tubular services		5	%		6	%							5	%
Total		25	%		25	%							22	%

YEAR ENDED DECEMBER 31, 2012 COMPARED TO YEAR ENDED DECEMBER 31, 2011

We reported net income attributable to the Company for the year ended December 31, 2012 of $448.6 million, or $8.10 per diluted share, including a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012. These results compare to net income attributable to the Company of $322.5 million, or $5.86 per diluted share, reported for the year ended December 31, 2011.

Revenues. Consolidated revenues increased $933.9 million, or 27%, in 2012 compared to 2011.

Our well site services segment revenues increased $59.7 million, or 9%, in 2012 compared to 2011 primarily due to increases in both completion services revenues and drilling services revenues. Our completion services revenues increased $34.6 million, or 7%, in 2012 compared to 2011 primarily due to increased demand for our completion services supporting the 2% increase in the U.S. rig count, a more favorable mix of higher value rentals and services and greater service intensity. Our drilling services revenues increased $25.1 million, or 15%, in 2012 compared to 2011 primarily as a result of increases in pricing, with average day rates rising to $18,000 per day in 2012, up from $16,400 per day in 2011, and increased utilization of our rigs from an average of approximately 82% in 2011 to an average of approximately 88% in 2012.

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Our accommodations segment reported revenues in 2012 that were $248.8 million, or 29%, above 2011. The increase in accommodations revenue primarily resulted from increased revenues from expanded room capacity in Canada and Australia along with $18.3 million in revenue from a favorable contract settlement reported in our U.S. accommodations business during the first quarter of 2012. Revenues, average available rooms and revenue per available room (RevPAR) for our lodges and villages increased 36%, 23% and 11%, respectively, in 2012 compared to 2011.

Our offshore products segment revenues increased $218.3 million, or 37%, in 2012 compared to 2011. This increase was primarily the result of higher levels of manufacturing and service activity, an improved revenue mix favoring our production equipment and connector products along with contributions from the acquisition of Piper which closed in July 2012.

Our tubular services segment revenues increased $407.1 million, or 30%, in 2012 compared to 2011. This increase was primarily a result of an increase in tons shipped from 699,000 in 2011 to 862,700 in 2012, an increase of 163,700 tons, or 23%. Higher volume resulted from the 2% increase in U.S. drilling and completion activity, market share gains in the U.S. and incremental customer programs in the U.S. Gulf of Mexico and certain U.S. shale basins. We also reported a 5% increase in realized revenues per ton shipped in 2012 compared to 2011 due to a more favorable mix of OCTG grades sold.

Cost of Sales and Service. Our consolidated cost of sales increased $693.7 million, or 27%, in 2012 compared to 2011. This cost of sales increase was directly related to the increase in revenue. Our consolidated gross margin as a percentage of revenues remained constant at 25% in 2012 and 2011.

Our well site services segment cost of sales increased $36.7 million, or 9%, in 2012 compared to 2011 as a result of a $26.2 million, or 9%, increase in completion services cost of sales and a $10.5 million, or 9%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues remained constant at 36% in both 2012 and 2011. Our completion services gross margin as a percentage of revenues declined modestly to 38% in 2012 compared to 39% in 2011. Our drilling services gross margin as a percentage of revenues increased from 26% in 2011 to 30% in 2012 primarily due to increased day rates, rig utilization and cost absorption.

Our accommodations segment cost of sales increased $95.9 million, or 21%, in 2012 compared to 2011 primarily due to increased revenues and room capacity in both Canada and Australia. Our accommodations segment gross margin as a percentage of revenues increased from 47% in 2011 to 50% in 2012 primarily due to an 11% increase in RevPAR for lodges and villages in 2012 compared to 2011. The increase in the RevPAR in 2012 compared to 2011 was primarily due to increased occupancy levels.

Our offshore products segment cost of sales increased $165.9 million, or 39%, in 2012 compared to 2011 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased modestly to 26% in 2012 compared to 27% in 2011.

Our tubular services segment cost of sales increased by $395.2 million, or 31%, in 2012 compared to 2011 primarily as a result of an increase in tons shipped. Our tubular services segment gross margin as a percentage of revenues decreased from 6.0% in 2011 to 5.3% in 2012 primarily due to lower margin sales into certain onshore markets as a result of declining OCTG prices throughout 2012.

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) expense increased $21.2 million, or 12%, in 2012 compared to 2011 primarily due to increased employee-related costs related to an 8% increase in total headcount, commissions and office expenses along with SG&A expense associated with the inclusion of Piper, which was acquired in July 2012.

Depreciation and Amortization. Depreciation and amortization expense increased $42.0 million, or 22%, in 2012 compared to 2011 primarily due to capital expenditures made during 2011 and 2012 largely related to investments in our Canadian and Australian accommodations and completion services businesses.

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Operating Income. Consolidated operating income increased $176.3 million, or 35%, in 2012 compared to 2011 primarily as a result of an increase in operating income from our accommodations segment of $115.7 million, or 46%, due to expanded room capacity in Canada and Australia, along with the favorable contract settlement reported in our U.S. accommodations business and an increase in operating income from our offshore products segment of $39.4 million, or 42%. In addition, operating income from our well site services segment increased $15.5 million, or 11%, largely due to increased dayrates and rig utilization in our drilling services business and a more favorable mix of services and increased activity in our completion services business. Operating income from our tubular services segment increased $10.6 million, or 16%, in 2012 compared to 2011 primarily as a result of the increase in tons shipped.

Interest Expense and Interest Income. Net interest expense increased by $11.5 million, or 21%, in 2012 compared to 2011 primarily due to interest expense on the 6 1/2% Senior Notes due 2019 (6 1/2% Notes), issued on June 1, 2011, partially offset by decreased interest expense on our 2 3/8% Notes due 2025 (2 3/8% Notes) due to their conversion in July 2012. The weighted average interest rate on borrowings outstanding under the Company’s credit facilities was 3.0% in 2012 compared to 3.1% in 2011. Interest income decreased as a result of decreased cash balances in interest bearing accounts.

Income Tax Expense. Our income tax provision for 2012 totaled $177.0 million, or 28.2% of pretax income, compared to income tax expense of $131.6 million, or 28.9% of pretax income, for 2011. The effective tax rates of 28.2% and 28.9% for the years ended December 31, 2012 and 2011, respectively, are comparable and are lower than U.S. statutory rates because of lower foreign tax rates.

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 completion services revenues. Our completion 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. This cost of sales increase was directly related to the increase in revenue. 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.

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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 completion 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 completion 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.

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. 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 completion 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 6 1/2% Notes issued on June 1, 2011, 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.

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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 completion services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our credit facilities and capital market transactions. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

Cash totaling $637.5 million was provided by operations during the year ended December 31, 2012 compared to cash totaling $215.9 million provided by operations during the year ended December 31, 2011. During 2012, $74.9 million was used to fund working capital, primarily due to increased investments in receivables and inventory in our offshore products segment coupled with higher OCTG inventory at our tubular services segment due to increased order activity. 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.

Cash was used in investing activities during the years ended December 31, 2012 and 2011 in the amounts of $577.0 million and $489.0 million, respectively. Capital expenditures totaled $487.9 million and $487.5 million during the years ended December 31, 2012 and 2011, 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 Australian mining developments.

During the year ended December 31, 2012, we spent cash of $80.4 million to acquire all of the operating assets of Piper and all of the equity of Tempress. In addition, the Company funded escrow accounts totaling $25.3 million related to contingent consideration and seller transaction indemnities for the Tempress acquisition. This compares to $2.2 million spent during the year ended December 31, 2011 to acquire an open camp accommodations facility in Carrizo Springs, Texas to provide accommodations support to customers working in the Eagle Ford shale basin. The Company funded the acquisitions of Piper and Tempress from amounts available under the Company’s U.S. revolving 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 million to $650 million for capital expenditures during 2013 to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total estimated 2013 capital expenditures are expected to be spent in our accommodations segment. We expect to fund these capital expenditures with cash available, internally generated funds and borrowings under our U.S., Canadian and Australian credit facilities. The foregoing capital expenditure forecast 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. At December 31, 2012, we had cash totaling $191.7 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where, in the case of Canada, we have assumed indefinite reinvestment of earnings and where we have not recorded a U.S. tax liability upon the assumed repatriation of foreign earnings. We believe these cash balances will be utilized for future investment outside the United States.

Net cash of $120.6 million was provided by financing activities during the year ended December 31, 2012, primarily as a result of proceeds from the issuance in the fourth quarter of 2012 of $400 million aggregate principal amount of 5 1/8% Senior Notes due 2023 (5 1/8% Notes), offset by net repayments of outstanding amounts under our revolving credit facilities, payments of principal amounts on the conversion of our 2 3/8% Notes and repayments on our U.S. and Canadian term loans. 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 $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 the 6 1/2% Notes due in 2019, offset by net repayments of outstanding amounts under our revolving credit facilities. We incurred $7.9 million of costs to secure financings in 2012 compared to $13.5 million in 2011. See Note 8 to the Consolidated Financial Statements included in this Annual Report for additional information on our debt offerings.

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On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $175 million in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. The 2 3/8% Notes were convertible by the holders thereof into shares of the Company’s common stock at the conversion rate of 31.496 shares of common stock for each $1,000 principal amount of 2 3/8% Notes converted. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $175 million aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s common stock valued at $220.6 million. See Note 8 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

We believe that cash on hand, cash flow from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global 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 23, 2012, the Company announced that its Board of Directors authorized $200 million for the repurchase of the Company’s common stock, par value $.01 per share. The authorization replaced the prior share repurchase authorization, which was set to expire on September 1, 2012. As of December 31, 2012, the Company had approximately 54.7 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2014. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of December 31, 2012, a total of $15.2 million of our stock (225,796 shares) had been repurchased under this program, leaving a total authorization of up to approximately $184.8 million remaining available under the program.

Credit Facilities. Our current bank credit facilities include a U.S. revolving credit facility, a U.S. term loan, a Canadian revolving facility, and a Canadian term loan. The credit facilities are governed by an Amended and Restated Credit Agreement dated of December 10, 2010 (Credit Agreement) by and among the Company, PTI Group Inc., PTI Premium Camp Services, Ltd., the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent and U.S. collateral agent and Royal Bank of Canada, as Canadian administrative agent and Canadian collateral agent. The U.S. and Canadian revolving credit facilities contain total commitments available of $1.05 billion, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $700 million (including $200 million in U.S. term loans), and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $350 million (including $100 million in Canadian 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 $25.3 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.

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The Credit Agreement 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, 2012, we were in compliance with our debt covenants and expect to continue to be in compliance during 2013. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During the year 2012, our applicable margin over LIBOR ranged from 2.00% to 2.25% and it was 2.00% as of December 31, 2012. Our weighted average interest rate paid under the Credit Agreement was 2.7% during the year ended December 31, 2012 and 3.0% for the year ended December 31, 2011.

As of December 31, 2012, we had $255.8 million outstanding under the Credit Agreement and an additional $41.1 million of outstanding letters of credit, leaving $708.9 million available to be drawn under the U.S. and Canadian facilities.

On September 18, 2012, the Company’s Australian accommodations subsidiary, The MAC Services Group Pty Limited (The MAC), entered into a AUD$300 million revolving loan facility governed by a Syndicated Facility Agreement (The MAC Group Facility Agreement), between The MAC, J.P. Morgan Australia Limited, as Australian agent and security trustee, JPMorgan Chase Bank, N.A., as U.S. agent, and the lenders party thereto, which is guaranteed by the Company and The MAC’s subsidiaries. The maturity date of The MAC Group Facility Agreement is December 10, 2015. The MAC Group Facility Agreement replaced The MAC’s previous AUD$150 million revolving loan facility. As of December 31, 2012, we had AUD$46 million outstanding under the Australian credit facility, leaving AUD$254 million available to be drawn under this facility. Our weighted average interest rate paid under the MAC Group Facility Agreement was 5.4% during the period beginning September 18, 2012 and ending December 31, 2012.

5 1/8% Notes. On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Notes through a private placement to qualified institutional buyers.

The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15, 2018, the Company may redeem some or all of the 5 1/8% 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 January 15,	% of Principal Amount
2018	102.563	%
2019	101.708	%
2020	100.854	%
2021 and thereafter	100.000	%

The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.

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On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes 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 5 1/8% 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 5 1/8% Notes 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 5 1/8% Notes Indenture contains customary events of default. As of December 31, 2012, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.

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

The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our 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 106.5% 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 and thereafter	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 U.S. and Canadian 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 6 1/2% Notes Indenture) with 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 6 1/2% Notes 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 6 1/2% Notes Indenture contains customary events of default. As of December 31, 2012, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.

Our total debt represented 34.7% of our combined total debt and shareholders’ equity at December 31, 2012 compared to 37.5% at December 31, 2011.

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Contractual Obligations. The following summarizes our contractual obligations at December 31, 2012, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):

	Payments due by period
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Contractual obligations
Total debt, including capital leases(1)	$	1,765,475	$	89,980	$	393,193	$	119,612	$	1,162,690
Purchase obligations		451,848		416,254		35,594		-		-
Non-cancelable operating lease obligations(2)		77,363		15,069		23,531		14,671		24,092
Asset retirement obligations - expected cash payments		16,350		344		271		904		14,831
Other non-current liabilities		25,089		-		25,089		-		-
Total contractual cash obligations	$	2,336,125	$	521,647	$	477,678	$	135,187	$	1,201,613

(1)

Includes interest on fixed-rate debt. Excludes interest on variable-rate 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, 2012 and include applicable commitment fees, estimated interest payments on our credit facilities would be $20.0 million “due in less than one year” and $36.9 million “due in one to three 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 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional for additional information on our credit facilities.

(2)

See Note 13 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information.

Our debt obligations at December 31, 2012 are included in our consolidated balance sheet, which is a part of our Consolidated Financial Statements included in this Annual Report on Form 10-K. We have not entered into any material leases subsequent to December 31, 2012.

Due to the uncertainty with respect to the timing of future cash flows associated with our uncertain tax positions at December 31, 2012, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. Therefore, $1.0 million in uncertain tax positions, including interest and penalties, have been excluded from the contractual obligations table above.

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, 2012, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

Tax Matters

Our primary deferred tax assets at December 31, 2012, 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, 2012 totaled $177.0 million, or 28.2% of pretax income, compared to $131.6 million, or 28.9% of pretax income, for the year ended December 31, 2011. The effective tax rates of 28.2% and 28.9% for the years ended December 31, 2012 and 2011, respectively, are comparable and are lower than U.S. statutory rates because of lower foreign tax rates.

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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 (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 their fair value or 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 future consideration due sellers as a result of the terms of a business combination, 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, 2012, $5.5 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. Total accretion expense related to the ARO was $0.3 million in 2012. 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.

Tangible and Intangible Assets, including Goodwill

Our goodwill totaled $520.8 million, or 11.7%, of our total assets, as of December 31, 2012. Our other intangible assets totaled $146.1 million, or 3.3%, of our total assets, as of December 31, 2012. The assessment of impairment on long-lived assets, including intangibles, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. Indicators of impairment might include persistent negative economic trends affecting the markets we serve, recurring losses or lowered expectations of future cash flows expected to be generated by our assets. 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.

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