ois20131231_10k.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, 2013

or

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ________

 

Commission file no. 001-16337

 

Oil States International, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

76-0476605

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

 

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

(Address of principal executive offices) (Zip Code)

 

Registrant's telephone number, including area code:

(713) 652-0582

 

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

 

Title of Each Class

Name of Exchange on Which Registered

Common Stock, par value $.01 per share

New York Stock Exchange

 

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

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [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 [ ]

 

 
 

 

 

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 30, 2013, was $5,054,536,782.

 

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding as of February 21, 2014 was 53,340,650 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement for the 2014 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

23 – 38

Item 1B.

Unresolved Staff Comments

38

Item 2.

Properties

38 – 39

Item 3.

Legal Proceedings

39

Item 4.

Mine Safety Disclosures

40

 

PART II

 

Item 5.

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 40 – 43

Item 6.

Selected Financial Data

44 – 45

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

46 – 65

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

65

Item 8.

Financial Statements and Supplementary Data

65

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

65

Item 9A.

Controls and Procedures

66

Item 9B.

Other Information

67

 

PART III

 

Item 10.

Directors, Executive Officers and Corporate Governance

67

Item 11.

Executive Compensation

67

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 67

Item 13.

Certain Relationships and Related Transactions, and Director Independence

67

Item 14.

Principal Accounting Fees and Services

67

 

PART IV

 

Item 15.

Exhibits, Financial Statement Schedules

67 – 73

SIGNATURES

74

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

75

 

 
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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

 

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. Such statements may include statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions. 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 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 supply and of demand for oil, natural gas, coal and other minerals;

 

 

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

 

 

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

 

 

the level of drilling and completion activity;

 

 

the level of activity and development in the Australian mining sector;

 

 

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 and mining;

 

 

the level of offshore oil and natural gas developmental activities;

 

 

general global economic conditions;

 

 

global weather conditions and natural disasters;

 

 

our ability to find and retain skilled personnel;

 

 

the availability and cost of capital; and

 

 

the other factors identified in “Part I, Item 1A. "Risk Factors."”

 

 
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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.

 

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 some of the world's most active oil, coal, natural gas and iron ore producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and West 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 three principal business segments – accommodations, offshore products and well site 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 our subsidiaries.

 

Available Information

 

The Company maintains a website with the address of 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) has documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company's Corporate Governance Guidelines, Corporate 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.”

 

 
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Tubular Services Business Disposition

 

On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu Tubulars America, Inc. (Marubeni-Itochu) for the sale of Sooner, Inc. and its subsidiaries (Sooner), which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600.0 million in cash, which remains subject to customary post-closing adjustments. We recognized a net gain on disposal of $128.4 million ($84.0 million after-tax) during 2013, which is included within “Net income from discontinued operations, net of tax” in the Consolidated Statements of Income. Operating results for the Company’s tubular services business have been classified as discontinued operations for all periods presented.

 

Proposed Spin-off of Accommodations Business

 

On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to the Company’s shareholders. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors, and is expected to be completed in the second quarter of 2014. The Accommodations business will initially be spun-off as a C-Corporation, which offers a faster path to separation. The Accommodations business will continue to assess the feasibility and advisability of a potential future conversion into a real estate investment trust (REIT).

 

Capital Spending and Acquisitions

 

Capital spending over the last five years has included both growth and maintenance capital expenditures in each of our businesses. Capital spending totaled $1.4 billion over the three-year period 2011 to 2013, 67% of which was spent in our accommodations segment.

 

In addition to capital spending, we have invested $144 million over the three-year period 2011 to 2013 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 2, 2013, we acquired all of the equity of Quality Connector Systems, LLC (QCS) for total cash consideration of $42.5 million. Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. The operations of QCS have been included in our offshore products segment since the acquisition date.

 

On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $49.8 million consisting of $32.8 million in cash plus contingent consideration with an estimated fair value of $17.0 million at closing. During 2013, the estimated fair market value of the contingent liability was increased to $20.0 million due to favorable developments related to a patent application by Tempress, resulting in a $3.0 million, or $0.05 per diluted share, charge to other operating expense. The patent was granted in the third quarter of 2013 and the $20.0 million of contingent consideration was paid to the former shareholders of Tempress. The Company’s current escrowed deposits of $5.3 million include other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for escrowed amounts expected to be paid to the seller also totaled $5.3 million and are classified as “Other current liabilities” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent liabilities” in our December 31, 2012 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.

 

 
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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.

 

The Company funded all of its acquisitions with cash on hand and/or amounts available under our credit facilities. See Note 10 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 16 to the Consolidated Financial Statements included in “Part II, Item 8. Financial Statements and Supplementary Data” for financial information by segment and a geographical breakout of revenues and long-lived assets for each of the three years ended December 31, 2013, 2012 and 2011. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers' willingness to spend capital on the exploration for and development of oil, natural gas, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our products and services is highly sensitive to current and expected commodity prices.

 

Our historical financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments. Due to the acquisition of The MAC Services Group Limited (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 customer activity levels related to oil sands deposits in Alberta, Canada, activity levels in support of natural resources production in Australia and oil and gas production in Canada and the United States. 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 seven years.

 

As a result of the positive outlook for long-term oil demand, along with continued high oil prices during the last three years, bidding and quoting activity for our offshore products has increased since the latter part of 2010. As a result of this increased activity and our acquisitions, backlog in our offshore products segment has steadily increased from $535 million at December 31, 2011 to $561 million as of December 31, 2012, and to a year-end record of $580 million as of December 31, 2013. We anticipate global deepwater capital spending to continue at robust levels due to new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico and Southeast Asia.

 

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. As recently as 2008, overall North American drilling and completion activity was 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 and lower natural gas prices, drilling and completion 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. as of February 14, 2014 totals approximately 1,423 rigs, comprising approximately 81% of total U.S. drilling activity.

 

 
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Accommodations

 

Overview

 

During the year ended December 31, 2013, we generated approximately 39% of our revenue and 47% of our operating income, before corporate charges, from our accommodations segment. We are one of North America's and Australia’s largest integrated providers of accommodations services for people working in remote locations. Our scalable modular facilities provide temporary and long-term 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.

 

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 primarily influenced by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year production phase of 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 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 country’s economy through its position as the largest contributor to exports and a major contributor to the country’s gross domestic product, employment and government revenue. Australia has broad natural resources including metallurgical and thermal coal, conventional and coal seam gas, base metals, iron ore and precious metals such as gold. The growth of Australian commodity exports over the last decade has been largely driven by strong Asian demand for coal, iron ore and liquefied natural gas (LNG). 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 been an important driver of growth for our Australian business and, while having slowed recently, remains a key ingredient for our continued growth in Australia. This commodity demand is expected to underpin continued investment and long-term 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, allowing them to focus their efforts and resources on their core development and production businesses.

 

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). We provide a full service hospitality function at our lodges including reservation management, check in and check out, catering, housekeeping and facilities management. Our lodge guests receive the amenity level of a full-service hotel plus three meals a day. 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. During 2013, we added 512 rooms (net of retirements) to our major Canadian oil sands lodges by expanding our Beaver River and Conklin Lodges and by opening Anzac Lodge, which was partially offset by a temporary reduction at Athabasca Lodge, as older rooms were removed to facilitate an expansion in the first quarter of 2014. Our Wapasu Creek Lodge is equivalent in size to the largest hotels in North America. In early 2014, the Company also announced the commencement of construction on a new oil sands lodge, McClelland Lake Lodge.

 

 
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Our Australian accommodations business operates ten villages with over 9,200 rooms currently, 7,506 rooms of which service the Bowen Basin region of Queensland, one of the premier metallurgical coal basins in the world. We provide accommodations services on a day rate basis to mining and related service companies (including construction contractors) under medium-term contracts (three to five years) with minimum nightly room commitments. Our Australian accommodations villages are strategically located in proximity to long-lived, low-cost mines operated by large mining companies. During 2013, we added 644 rooms (net of retirements) to our Australian accommodations business by expanding existing villages and by constructing and opening one new village, Boggabri Village, to serve the Gunnedah Basin.

 

More than three-fourths 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:

 

   

As of December 31,

 
   

2013

   

2012

   

2011

 
                   

Canadian Oil Sands Lodges

                       
                         

Wapasu

    5,174       5,174       5,174  

Henday

    1,698       1,698       1,120  

Athabasca

    1,557       1,877       1,776  

Beaver River

    1,094       876       732  

Conklin

    1,036       948       584  

Anzac

    526       -       -  

Lakeside

    510       510       510  

Total Rooms

    11,595       11,083       9,896  
                         

Australian Villages

                       
                         

Coppabella

    3,048       2,912       2,556  

Dysart

    1,912       1,912       1,491  

Moranbah

    1,240       1,240       1,180  

Middlemount

    816       816       816  

Narrabri

    502       502       242  

Boggabri

    508       -       -  

Nebo

    490       490       490  

Calliope

    300       300       300  

Kambalda

    238       238       238  

Karratha

    208       208       -  

Total Rooms

    9,262       8,618       7,313  

 

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 (SAGD) drilling operations and large shale oil projects.

 

As part of our integrated business model, we utilize a flexible manufacturing strategy that combines internal manufacturing capabilities and outsourced manufacturing partners to allow us to respond quickly to changing customer needs and timing. We own two accommodations manufacturing plants near Edmonton, Alberta, Canada, along with manufacturing facilities in Johnstown, Colorado and Belle Chasse, Louisiana. Additionally, we lease a manufacturing plant in Ormeau, Queensland, Australia.   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 $1.3 billion, or 53%, of our total consolidated capital expenditures on our Canadian and Australian accommodations businesses.

 

 
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Regions of Operations

 

Our accommodations business is focused primarily in northern Alberta, 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, the Permian Basin 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 primarily operate in 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 2013 were Imperial Oil Limited (a company controlled by ExxonMobil Corporation) and Fluor Canada Ltd in Canada and BM Alliance Coal Operations Pty Ltd (an alliance between BHP Billiton and Mitsubishi) in Australia.

 

Our primary competitors in North America include Aramark Corporation, Compass Group, ATCO Structures & Logistics Ltd., Black Diamond Group Limited, Horizon North Logistics Inc., and Clean Harbors, Inc. Our primary competitors in Australia include Ausco Modular (a subsidiary of Algeco Scotsman), Fleetwood Corporation, Aramark Corporation, Sodexo and Compass Group PLC.

 

Historically, many customers have invested in their own accommodations. 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. We believe this represents a growth opportunity for us. We believe customers will increasingly outsource accommodations to more efficiently deploy capital for core resource development operations. 

 

Offshore Products

 

Overview

 

During the year ended December 31, 2013, we generated approximately 33% of our revenue and 27% 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 riser systems, 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, drive spending for these activities.

 

Products and Services

 

Celebrating over 70 years of operations in 2013, 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 also 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.

 

 
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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 and jack-up rigs. Our products and services include:

 

 

flexible bearings and advanced connection systems;

 

 

casing and conductor connections and pipe;

 

 

subsea pipeline products;

 

 

compact ball valves, manifold system components and diverter valves;

 

 

marine winches, mooring systems, cranes and other heavy-lift rig equipment;

 

 

production, workover, completion and drilling riser systems and their related repair services;

 

 

blowout preventer (BOP) stack assembly, integration, testing and repair services; and

 

 

other products and services.

 

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 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.

 

 
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Casing and Conductor Connections and Pipe. 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;

 

 

deep and shallow water pipeline connectors;

 

 

midline tie-in sleds;

 

 

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

 

 

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

 

 

electrical isolation joints; and

 

 

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

 

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

 

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

 

 

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

 

 

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

 

 

misalignment and swivel ring flanges; and

 

 

pipe recovery tools for recovering dropped or damaged pipelines.

 

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

 

Compact Ball Valves, Manifold System Components and Diverter Valves. Our Piper division designs and manufactures compact high pressure valves and manifold system components for all environments of the oil and gas industry including onshore, offshore, drilling and subsea applications. Our valve and manifold bores are designed to closely match the inside diameter of the required pipe schedule for the system working pressure. The result is elimination of piping transition areas that minimize erosion and system friction pressure loss, resulting in a more efficient flow path.  Our floating ball valve design with its large ball/seat interface has over 30 years of field service experience in upstream unprocessed produced liquids and gasses, assuring reliable service.  Oil States Piper Valve Optimum Flow Technology is our way of helping end users maximize space, minimize weight and increase production. These products are designed and manufactured at our Oklahoma City, Oklahoma location.

 

 
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Marine Winches, Mooring Systems, Cranes and other Heavy-Lift 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 designed at our Houma, Louisiana location and manufactured at our Houma, Louisiana; Navi Mumbai, India; and Rayong, Thailand locations.

 

Production, Workover, Completion and Drilling Riser Systems and their related repair services. Utilizing the expertise of our welding technology group, we have again extended the boundaries of our Merlin™ connector technology with the design and manufacture of multiple riser systems. The unique Merlin™ connection has proven to be a robust solution for even the most demanding high-pressure (up to 10,000 psi) riser systems used in high-fatigue, deepwater applications. Our riser systems are designed to meet a range of static and fatigue stresses on a par with those of our Tension Leg Elements (TLE) connectors. The connector can be welded or machined directly onto upset riser pipe and provide sufficient material to perform "re-cuts" after extended service. Our marine riser offers unmatched tension capabilities together with one of the fastest run times in the industry. Auxiliary riser system components and running tools can be provided along with full service inspection and repair of these riser systems by our facilities worldwide.

 

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.

 

Other Products & Services.   Our offshore products segment also produces a variety of products for use in applications other than in the offshore oil and gas industry. For example, we provide:

 

 

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.

 

Backlog. Backlog in our offshore products segment was $580 million at December 31, 2013, compared to $561 million at December 31, 2012 and $535 million at December 31, 2011. We expect approximately 90% of our backlog at December 31, 2013 to be recognized as revenue during 2014. 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. However, backlog cancellations have not been significant in the past. 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.

  

 
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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 2013 were Saipem, Halliburton Company, and Heerema Marine Contractors. 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, 2013, we generated approximately 28% of our revenue and 26% of our operating income, before corporate charges, from our well site services segment. Our well site services segment includes a broad range of products and services that are used to drill for, establish and maintain the flow of oil 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 both in onshore and offshore applications throughout the drilling, completion and production phases of a well's life.

 

Well Site Services Market

 

Historically, demand for our completion services and drilling services has been predominately tied to the level of oil and natural gas exploration and production activity in the United States. 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, which is primarily marketed through the brand names Oil States Energy Services and Tempress, provides a wide range of services for use in the onshore and offshore oil and gas industry, including:

 

 

wellhead isolation services;

 

 

wireline and coiled tubing support services;

 

 

frac valve and flowback services;

 

 

well testing, including separators and line heaters;

 

 

ball launching services;

  

 
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pipe recovery systems;

 

 

thru-tubing milling and fishing services;

 

 

hydraulic chokes and manifolds;

 

 

blow out preventers;

 

 

downhole extended-reach technology; and

 

 

gravel pack operations on well bores.

 

Employees in our completion services business typically rig up and operate our equipment on the well site for our customers. Our completion services equipment is primarily used during the completion and production stages of a well. As of December 31, 2013, we provided completion services at approximately 53 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 have closed facilities in areas where operations are marginal in order to streamline operations and enhance our facilities to improve operational efficiency. We typically provide our services and equipment based on daily rates which vary depending on the type of equipment and the length of the job. 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 2013 were Anadarko Petroleum Corporation, Devon Energy Corporation and Chevron 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 under the brand name Capstar Drilling, our wholly-owned subsidiary, is located in the United States and provides land drilling services for shallow to medium depth wells of up to 10,000 to 12,000 feet and, under more limited conditions, up 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, 2013, we had a total of thirty-four semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds, fifteen of which were fabricated and/or assembled in our Odessa, Texas facility during the last ten years with components purchased from specialty vendors. Twenty-four of these drilling rigs are based in the Permian Basin and ten are based in the Rocky Mountain region. Utilization of our drilling rigs decreased from an average of 88% in 2012 to an average of 75% in 2013. On December 31, 2013, twenty-nine of our rigs, or 85%, 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 2013 were Apache Corporation, Energen Resources Corporation and Crescent Point Energy Corporation. 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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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 regions restricts operations in the second quarter of our fiscal year and adversely affects our operations and our ability to provide services. During the Australian rainy season between 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 interrupted by hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast.

 

Employees

 

As of December 31, 2013, the Company employed 9,167 full-time employees on a consolidated basis, 42% of whom are in our accommodations segment, 29% of whom are in our well site services segment, 28% of whom are in our offshore products segment and 1% of whom are in our corporate headquarters. We were party to collective bargaining agreements covering approximately 2,400 employees located in Canada, Australia, the United Kingdom and Argentina as of December 31, 2013. 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. To the extent that these laws and regulations impose more stringent requirements or increased costs or delays upon our customers in the performance of their operations, the resulting demand for our products and services by those customers may be adversely affected, which impact could be significant and long-lasting. Moreover, changes in these laws and regulations, including more restrictive standards and increased levels of enforcement, 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 or regulations, amendments of existing laws or regulations, or changes in enforcement policies.

 

Our operations and the operations of our customers for whom we provide our products and services 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 have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions to achieve and maintain compliance. 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 adverse 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 upon us or our customers that we cannot currently quantify.

 

For example, in Canada, in February 2012, the governments of Canada and Alberta released the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring that was to be phased in between 2012 and 2015. The costs of implementing this plan are to be funded by industry members, some of whom are our customers. This new monitoring regime is now in the process of being implemented and has increased the levels of monitoring in the Canadian oil sands and may increase costs for us and our customers. This could reduce natural resource extraction activity and, consequently, demand for our services.

 

Alberta is also in the process of establishing land-use frameworks which will apply to the various regions of Alberta. To date, only the Lower Athabasca Regional Plan has been completed and has the force of law. Several Alberta government initiatives are being implemented through this regional plan including enhancements to the reclamation security policy regarding mine site (including oil sands mines) reclamation, the environmental management framework for cumulative effects to air, surface water and ground water resulting from oil, oil sands and gas extraction activities, and Alberta's Wetland Policy, These initiatives and enhancements may increase costs for us or our clients or may curtail our or our client's future operations.

 

 
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With regard to our operations in the United States, we generate wastes, including non-hazardous solid wastes and hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. With authority delegated from the United States Environmental Protection Agency, or “EPA,” most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas exploration and production, if properly handled, are exempt from regulation as hazardous waste under RCRA. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, 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 our oil and natural gas exploration and production customers to more rigorous and costly operating and disposal requirements, which could reduce demand for the products and services we provide and result in a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes.

 

Also in connection with our operations in the United States, 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 operations in the United States, 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 domestic properties upon which we operate 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 the domestic properties upon which we operate require permits for discharges of wastewater and/or storm water, and we have developed a system for securing and maintaining these permits, where required. 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 natural gas exploration and production 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. For example, 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 has  issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 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, any or all of which could reduce demand for our completion services business.

 

In addition, certain governmental reviews in the United States 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. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review in 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. Also, in May 2013, the federal Bureau of Land Management, or BLM, published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing or any future 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 performed by our customers, and thus reduce demand for our North American completion products and services and accommodations services.

  

In response to an April 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-deepwater in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the U.S. Department of the Interior (DOI) and its implementing agencies that have since evolved into the present day Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE), has issued various rules, Notices to Lessees and Operators (NTLs) and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration and production operators in the Gulf of Mexico. These new regulatory requirements include the following:

 

 

The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;

 

 

The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;

 

 

The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and

 

 

The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system (SEMS) to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.

 

 
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These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we conduct operations, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.

 

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, in 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. 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, and from pneumatic controllers and storage vessels, beginning as early as October 15, 2012.

 

        Past scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or GHG, and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In 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% from 2006 levels by 2050. One measure the government of Canada has undertaken in pursuit of this objective is to regulate greenhouse gas emissions on a sector by sector basis. The oil and gas sector has yet to be subject to specific emission targets but when and if such specific emission targets are established, the costs of complying with such emission targets may adversely affect our and our clients' levels of activity in the energy sector and our respective financial results.

 

 
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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 of carbon dioxide equivalent from a facility in a calendar 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 overlapping regulations may adversely affect our operations and financial results as well as those of our customers with whom we conduct business.

 

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 under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay or ability to obtain air permits for new or modified sources that are major sources of GHG emissions. 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.

 

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. The adoption of legislation or regulatory programs to reduce emissions of GHGs 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 GHGs 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 GHGs 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.

 

 
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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 GHGs that are imposed in foreign countries in which we operate, could adversely affect demand for our services.

 

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.  The Australian Commonwealth Government’s carbon pricing mechanism (“CPM”) commenced on July 1, 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. The recently elected Australian federal government introduced a bill to Parliament in late 2013 to repeal the CPM legislation, but does not yet have sufficient support in the upper house for this bill to be passed. 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 result could have an adverse effect on our Australian operations and financial results.

 

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 numerous 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.

 

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

 

In addition, 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.

 

 
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Disclosure under Section 13® of the Exchange Act

 

The Iran Threat Reduction and Syria Human Rights Act of 2012, signed into law by President Obama on August 10, 2012, added a new Section 13(r) to the Exchange Act, which requires us to disclose whether the Company or any of its affiliates has engaged in certain Iran-related activities during the reporting period. During the year ended December 31, 2013, our wholly-owned Singaporean subsidiary, Oil States (Asia) Ptd Ltd (“Oil States (Asia)”), made two shipments and received three payments in connection with a prior transaction for the sale of riser pipe and associated material to a United Arab Emirates company, for ultimate use in the South Pars Gas Field. This field is controlled and mandated by Pars Oil & Gas Co, an entity designated in December 2010 by the Office of Foreign Assets Control (OFAC) as being owned or controlled by the Government of Iran. The transaction that is the subject of this disclosure commenced at a time when Oil States (Asia) was not subject to the Iranian Transactions and Sanctions Regulations, 31 C.F.R. Part 560 (ITSR). The total value of Oil States (Asia)’s transaction was approximately $4.2 million, for which it received an estimated net profit of $0.4 million. The three payments that Oil States (Asia) received during the reporting period totaled approximately $4.23 million. Except for the receipt of two final payments from its customer during April 2013, Oil States (Asia) completed the transaction in accordance with and during the validity period of the wind-down general license of ITSR Section 560.555, which expired on March 8, 2013. Oil States (Asia) has wound down its Iran-related business, and voluntary self-disclosures have been submitted to OFAC and the State Department about this transaction.

 

 
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Item 1A. Risk Factors

 

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

 

Our business is subject to a number of economic risks.

 

Financial markets worldwide experienced extreme disruption in the past 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 financial 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. 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 resource 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 these commodities, market uncertainty, and a variety of other factors that are beyond our control. Accordingly, a sudden or long-term decline in commodity pricing would have material adverse effects on our results of operations. Any prolonged reduction in commodity prices will depress levels of exploration, development, and production activity, often reflected as reductions in rig counts, employees 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 natural gas. Many factors affect the supply of 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;

 

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

 

 

the level of activity and development in the Australian mining sector;

 

 

the level of demand, particularly from China, for coal and other natural resources produced in Australia;

 

 

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

 

 

the availability of transportation infrastructure for oil, natural gas and coal, 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 developing countries, such as China and India;

 

 

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

 

 

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

 

 

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

 

 

rapid technological change and the timing and extent of development of energy sources, including LNG or other alternative fuels;

 

 

environmental regulation; and

 

 

domestic and foreign tax policies.

 

Due to the cyclical nature of the natural resources industry, our business may be adversely affected by extended periods of low oil, coal or natural gas prices or unsuccessful exploration results which may decrease our customers’ spending and therefore our results.

 

Commodity prices have been and are expected to remain volatile. This volatility causes oil and gas and mining companies and drilling contractors to change their strategies and expenditure levels. Prices of oil, coal and natural gas can be influenced by many factors, including reduced demand due to lower global economic growth, surplus inventory, improved technology such as the hydraulic fracturing of horizontally drilled wells in shale discoveries, access to potentially productive regions and availability of required infrastructure to deliver production to the marketplace. In particular, global demand for both oil and metallurgical coal is, at least partially, dependent on the growth of the Chinese economy. With growth in the Chinese economy, China’s demand for oil and steel increases driving demand for oil and metallurgical coal. Should GDP growth in China slow, demand for these commodities and, correspondingly, our accommodations would fall which would negatively impact our financial results.

 

 
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A significant portion of our business segments support projects that are capital intensive and require several years to generate first production. 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 commodity 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 revenues and profitability. In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Historically, WCS has traded at a discount to West Texas Intermediate (WTI) crude. Should the price of WTI decline or the WCS discount to WTI widen further, our oil sands customers may delay additional investments or reduce their spending in the oil sands region. Similarly, the volumes and prices of the mineral products of our customers, 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 customers 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 customers. We have experienced in the past, and expect to experience in the future, significant fluctuations in operating results based on these changes.

 

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells, which could 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 natural gas exploration and production 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. For example, 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 issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. 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.

 

In addition, certain governmental reviews in the United States 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. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review in 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. Also, in May 2013, BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing, proposed or any future 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 operators, some of which are performed by 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, any or all of which could reduce demand for the products and services of each of our business segments.

 

 
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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 our accommodations clients’ operations 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, higher costs 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 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 operations;

 

 

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

 

 

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

 

 

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

 

 

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

 

 

delays in or failure to commission new infrastructure in timeframes so as not to disrupt customer 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.

 

 
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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 often 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;

 

 

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 aboriginal or community interests, 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.

 

 
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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 response to an April 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-deepwater in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the DOI and its implementing agencies, BOEM and BSEE, has issued various rules, Notices to Lessees or Operators, or NTLs, and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration and production operators in the Gulf of Mexico. These new regulatory requirements include the following:

 

 

The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;


 

The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;


 

The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and


 

The Workplace Safety Rule, which requires operators to employ a comprehensive SEMS to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.

 

These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere in areas of the United States or foreign locations where we conduct operations, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.

 

Due to the significant concentration of our accommodations business in the oil sands region of Alberta, Canada and in the Bowen Basin coal region of Queensland, Australia, adverse events in these areas could negatively impact our accommodations business.

 

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. For example, in 2011, major flooding caused by seasonal rain and a cyclone impacted areas near our Australian villages. Also in 2011, forest fires in northern Alberta impacted areas near our Canadian lodges. Due to our geographic concentration, any adverse events or developments in our operating areas may disproportionately affect our financial results.

 

 
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The cyclical nature of our business and a severe prolonged downturn could negatively affect the value of our goodwill.

 

As of December 31, 2013, 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 each of our reporting units (completion services, drilling services, accommodations and offshore products) 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. 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.

 

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 50% (7% excluding Canada, the UK and Australia) of our consolidated revenue in the year ended December 31, 2013. Risks associated with our operations in foreign areas include, but are not limited to:

 

 

expropriation, confiscation or nationalization of assets;

 

 

 
 

renegotiation or nullification of existing contracts;

 

 

 
 

foreign exchange limitations;

 

 

 
 

foreign currency fluctuations;

 

 

 
 

foreign taxation;

 

 

 
 

the inability to repatriate earnings or capital in a tax efficient manner;

 

 

 
 

changing political conditions;

 

 

 
 

changing foreign and domestic monetary policies;

 

 

 
 

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

 

 

 
 

regional economic downturns.

 

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

 

 
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The regulatory regimes in some foreign countries may be substantially different than those in the United States, and may be unfamiliar to U.S. investors. Violations of foreign 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.

 

Exchange rate fluctuations could adversely affect our U.S. reported 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 revenues 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 revenues or earnings in countries whose 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 revenues 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, 2013, approximately 50% of our revenues originated from subsidiaries outside of the U.S. and were denominated 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 revenues, 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.

 

Our operations are significantly affected by stringent 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 under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though our conduct was lawful at the time it occurred or the conduct resulting in such damage and costs were 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 services at one of our or 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.

 

 
30

 

 

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 or imposing a carbon tax on emission of greenhouse gasses 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 of the United States 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 of our fiscal year. 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 of the United States can restrict access to work areas for our well site services and accommodations segment customers. 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.

 

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

 

In many cases, we subcontract the performance of portions 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.

 

 
32

 

 

We expect to gain certain business, financial and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize these intended benefits. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition. Additional risks we could face in connection with acquisitions include:

 

 

retaining key employees of acquired businesses;
   
   retaining and attracting new customers of acquired businesses;
   

retaining supply and distribution relationships key to the supply chain;
   

increased administrative burden;
   

developing our sales and marketing capabilities;
   

managing our growth effectively;
   

potential impairment resulting from the overpayment for an acquisition;
   
   integrating operations;
   

managing tax and foreign exchange exposure;
   

operating a new line of business;
   
   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 and our insurance may not cover certain liabilities, including litigation risks.

 

Our operations are subject to many hazards. 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. 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 also face the following other risks related to 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 counterparties to our insurance contracts may pose credit risks; and

 

 

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

 

 
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.

 

As a result of our customer concentration, 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. 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 could 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. 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 (2013 low sales price of $71.28 per share; 2013 high sales price of $113.64 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.

 

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 capacity 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 eight years and in Australia over the past three 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 natural resources regions of 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.

 

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.

 

 
36

 

 

Employee and customer labor problems could adversely affect us.

 

As of December 31, 2013, we are party to collective bargaining agreements covering 1,823 employees in Canada, 543 employees in Australia, 18 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 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 provide limitations on the removal of directors, on stockholder proposals at meetings of stockholders, on stockholder action by written consent and on the ability of stockholders to call special meetings, which 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.

 

The proposed spin-off of our accommodations business is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.

 

On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to our shareholders. We expect that the spin-off can be executed by the end of the second quarter of 2014. Our ability to timely effect the spin-off is subject to several conditions, including among other things, market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors. We cannot assure you that we will be able to complete the spin-off in a timely fashion, if at all. For these and other reasons, the spin-off may not be completed on the terms or timeline contemplated. Further, if the spin-off is completed, it may not achieve the intended results. Any such delays or difficulties could adversely affect our business, results of operations or financial condition.

 

We may be required to refinance our debt in connection with the contemplated spin-off of our accommodations business.

 

In connection with the proposed spin-off, we will be required to refinance all or a portion of our credit facilities and outstanding 5 1/8% Senior Notes (5 1/8% Notes) and 6 1/2% Senior Notes (6 1/2% Notes) unless we obtain the consent of our lenders under our credit facilities and the holders of the notes. If we are required to refinance our debt, we may be required to pay significant redemption premiums, and the terms of any new indebtedness may not be as favorable as our current debt. In addition, if refinancing opportunities are not available to us, we may be required to delay the consummation of the spin-off of our accommodations business.

 

 
37

 

 

Our business could be negatively affected as a result of the actions of activist shareholders.

 

Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases, sales of assets or even sale of the entire company. Given our shareholder composition and other factors, it is possible such shareholders or future activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our Board of Directors and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition.  Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the Board of Directors may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our, revenue, earnings and operating cash flows could be adversely affected.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties

 

The following table presents information about our principal properties and facilities. For a discussion about how each of our business segments utilizes its respective properties, please see “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)

 

30,931

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)

 

58,871

Offshore products service facility and office

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

Offshore products molding facility

Tulsa, Oklahoma (lease)

 

57,800

Offshore products molding facility

Oklahoma City, Oklahoma

 

70,000

Offshore products service facility and office

Lampasas, Texas

 

48,500

Offshore products molding facility

Lampasas, Texas (lease)

 

20,000

Offshore products warehouse

Johnstown, Colorado

 

153 acres

Accommodations manufacturing facility and yard

Killdeer, North Dakota

 

42 acres

Accommodations facility

Pecos, Texas 

 

35 acres

Accommodations facility

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

Casper, Wyoming (lease) 

 

14 acres

Accommodations 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

Windsor, Colorado (lease)

 

4,933

Accommodations office

Houston, Texas (lease)

 

23,441

Completion services office

Alice, Texas

 

27 acres

Completion services shop

Midland, Texas```

 

11 acres

Completion services shop

Houma, Louisiana

 

10 acres

Completion services shop

Rock Springs, Wyoming

 

10 acres

Completion services shop

Oklahoma City, Oklahoma

 

3 acres

Completion services shop

Odessa, Texas

 

22 acres

Well site services office, shop, warehouse and yard

Casper, Wyoming

 

7 acres

Well site services office, shop and yard

 

 
38

 

 

Location

 

Approximate 

Square

 Footage/

Acreage

Description

 

     

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

Acheson, Alberta (lease)

 

 40 acres

Accommodations office, yard and warehouse

Edmonton, Alberta

 

  33 acres

Accommodations manufacturing facility

Grimshaw, Alberta (lease)

 

 20 acres

Accommodations equipment yard

Fort McMurray, Alberta (Anzac Lodge) 

 

  18 acres

Accommodations facility

Nisku, Alberta

 

  9 acres

Accommodations manufacturing facility

Edmonton, Alberta (lease)

 

  86,376

Accommodations office and warehouse

Edmonton, Alberta (lease)

 

  71,654

Accommodations manufacturing facility and yard

Edmonton, Alberta (lease)

 

  28,253

Accommodations office

Edmonton, Alberta (lease)

 

  16,130

Accommodations office

       

Australia:

     

Coppabella, Queensland, Australia

 

198 acres 

Accommodations facility

Calliope, Queensland, Australia

 

  124 acres

Accommodations facility

Narrabri, New South Wales, Australia

 

  82 acres

Accommodations facility

Boggabri, New South Wales, Australia

 

  52 acres

Accommodations facility

Dysart, Queensland, Australia

 

  50 acres

Accommodations facility

Middlemount, Queensland, Australia

 

  37 acres

Accommodations facility

Karratha, Western Australia, Australia (own and 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

Sydney, New South Wales, Australia (lease)

 

  17,276

Accommodations office

Brisbane, Queensland, Australia (lease)

 

 7,115

Accommodations office

       

Other International:

     

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

Aberdeen, Scotland (lease)

 

  15 acres

Offshore products manufacturing facility and yard

Bathgate, Scotland

 

 3 acres

Offshore products manufacturing facility and yard

Rayong Province, Thailand

 

  11 acres

Offshore products manufacturing and service facility

Singapore (lease)

 

 155,398

Offshore products manufacturing facility

Barrow-in-Furness, England (own and lease)

 

  63,300

Offshore products service facility and yard

District Raigad, Maharashtra, India 

 

  3 acres

Offshore products manufacturing facility

 

We have a total of 53 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. Leases for our lodge properties in Canada refers to land leased from the Alberta government. We also lease land for our Karratha village from the local provincial government in Australia. Generally, our land leases have an initial term of ten years and will expire between 2015 and 2026.

 

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.

 

 
39

 

 

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 53,340,650 shares of common stock outstanding as of February 21, 2014. The approximate number of record holders of our common stock as of February 21, 2014 was 24. 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, 2014 was $96.09 per share.

 

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

 

   

Sales Price

 
   

High

   

Low

 

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  

2013

               

First Quarter

  $ 82.70     $ 71.28  

Second Quarter

    103.50       71.36  

Third Quarter

    106.84       88.21  

Fourth Quarter

    113.64       97.83  

 

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.

 

 
40

 

 

PERFORMANCE GRAPH

 

The following performance graph and chart compare the cumulative 5-year total stockholder return on the Company's common stock relative to the cumulative total returns of the Standard & Poor's 500 Stock Index, the Philadelphia OSX Index, an index of oil and gas related companies that represent an industry composite of the Company's peer group, and two customized peer groups of fourteen companies (our 2012 Proxy Peer Group) and fifteen companies (our 2013 Proxy Peer Group), respectively, whose individual companies are listed in footnotes (a) and (b) below for the period from December 31, 2008 to December 31, 2013. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2008 and assume the reinvestment of all dividends.

 

The fourteen companies included in the Company's first customized peer group are: Carbo Ceramics Inc., Core Laboratories, Dresser-Rand Group Inc., Dril-Quip Inc., Exterran Holdings Inc., FMC Technologies Inc.,  Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.

 

   The fifteen companies included in the Company's second customized peer group are: Cameron International Corp., Carbo Ceramics Inc., Core Laboratories, Dresser-Rand Group Inc., Dril-Quip Inc., Exterran Holdings Inc., FMC Technologies Inc., Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.

 

 
41

 

 

 

Oil States International – NYSE

 

 

   

Cumulative Total Return

 
   

12/08

   

12/09

   

12/10

   

12/11

   

12/12

   

12/13

 

OIL STATES INTERNATIONAL, INC.

  $ 100.00     $ 210.22     $ 342.91     $ 408.61     $ 382.77     $ 544.25  

S & P 500

    100.00       126.46       145.51       148.59       172.37       228.19  

PHLX OIL SERVICE SECTOR (OSX)

    100.00       165.26       205.16       174.89       177.39       230.95  

OLD PEER GROUP

    100.00       195.18       273.55       288.50       280.61       361.83  

NEW PEER GROUP

    100.00       189.97       264.76       274.91       270.93       350.94  

 

*$100 invested on December 31, 2008 in stock or index, including reinvestment of dividends. Fiscal year ending December 31st.

 

(1)

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

(2)

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

Prepared by Research Data Group, Inc. Used with permission. Copyright© 2014. All rights reserved. (www.researchdatagroup.com/S&P.htm).

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

None.

 

 
42

 

 

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, 2013 –

October 31, 2013

          6,685(2) 

   $108.62(3)

--

$ 472,865,339

November 1, 2013 –

November 30, 2013

  234,411(4)

   $102.37(5)

 234,309

$ 448,879,598

December 1, 2013 -

December 31, 2013

  790,121(6)

   $101.35(7)

789,904

$ 368,822,647

Total

1,031,217

$101.63

1,024,213

$ 368,822,647

 

 

(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. On September 6, 2013, we announced an increase in the program from $200,000,000 to $500,000,000. 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, 2013 and October 31, 2013, which represent the dates the restrictions lapsed on such shares.

 

(4)

Included in these shares are 102 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, 2013, which represents the date the restrictions lapsed on such shares.

 

(6)

Included in these shares are 217 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.

 

(7)

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 December 14, 2013 and December 15, 2013, which represents the dates the restrictions lapsed on such shares.

 

 
43

 

 

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, 2013. 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 and Supplementary Data” of this Annual Report on Form 10-K. In September 2013, we sold our tubular services segment and, accordingly, all periods presented below have been reclassified to reflect the presentation of our tubular services operations as discontinued operations.

 

Selected Financial Data

(In thousands, except per share amounts)

 

   

Year Ended December 31,

 
   

2013

   

2012

   

2011

   

2010

   

2009

 
                                         

Statement of Income Data:

                                       

Revenues

  $ 2,670,163     $ 2,631,189     $ 2,104,363     $ 1,442,820     $ 1,296,086  

Costs and Expenses:

                                       

Product costs, service and other costs

    1,662,710       1,606,004       1,307,430       956,488       883,579  

Selling, general and administrative expenses

    214,433       184,544       164,433       135,837       126,192  

Depreciation and amortization expense

    276,444       227,792       186,389       122,901       116,665  

Impairment of goodwill

    -       -       -       -       94,528  

Other operating (income) expense

    4,282       2,590       1,809       7,041       (2,606 )
      2,157,869       2,020,930       1,660,061       1,222,267       1,218,358  

Operating income

    512,294       610,259       444,302       220,553       77,728  

Interest expense, net of capitalized interest

    (75,902 )     (68,922 )     (57,506 )     (15,801 )     (15,250 )

Interest income

    2,353       1,583       1,700       751       380  

Loss on extinguishment of debt

    (7,374 )     -       -       (473 )     -  

Equity in (losses) earnings of unconsolidated affiliates

    (355 )     (419 )     (846 )     (25 )     203  

Other income

    5,325       9,272       3,094       135       286  

Income from continuing operations before income taxes

    436,341       551,773       390,744       205,140       63,347  

Income tax provision(1)

    (119,992 )     (149,016 )     (107,620 )     (65,178 )     (35,896 )

Net income from continuing operations

    316,349       402,757       283,124       139,962       27,451  

Net income from discontinued operations, net of tax (including a net gain on disposal of $84,043 in 2013)

    106,364       47,091       40,298       28,643       32,161  

Net income

    422,713       449,848       323,422       168,605       59,612  

Less: Net income attributable to noncontrolling interest

    1,455       1,239       969       587       498  
                                         

Net income attributable to Oil States International, Inc.

  $ 421,258     $ 448,609     $ 322,453     $ 168,018     $ 59,114  
                                         

Net income attributable to Oil States International, Inc.:

                                       

Continuing operations

  $ 314,894     $ 401,518     $ 282,155     $ 139,375     $ 26,953  

Discontinued operations

    106,364       47,091       40,298       28,643       32,161  

Net income attributable to Oil States International, Inc.

  $ 421,258     $ 448,609     $ 322,453     $ 168,018     $ 59,114  
                                         

Basic net income per share attributable to Oil States International, Inc. common stockholders from:

                                       

Continuing operations

  $ 5.67     $ 7.58     $ 5.51     $ 2.77     $ 0.54  

Discontinued operations

    1.91       0.89       0.79       0.57       0.65  

Net income

  $ 7.58     $ 8.47     $ 6.30     $ 3.34     $ 1.19  
                                         

Diluted net income per share attributable to Oil States International, Inc. common stockholders from:

                                       

Continuing operations

  $ 5.63     $ 7.25     $ 5.13     $ 2.65     $ 0.54  

Discontinued operations

    1.90       0.85       0.73       0.54       0.64  

Net income

  $ 7.53     $ 8.10     $ 5.86     $ 3.19     $ 1.18  
                                         

Weighted average number of common shares outstanding:

                                       

Basic

    55,572       52,959       51,163       50,238       49,625  

Diluted

    55,930       55,384       55,007       52,700       50,219  

 

 
44

 

 

   

Year Ended December 31,

 
   

2013

   

2012

   

2011

   

2010

   

2009

 

Other Data:

                                       

EBITDA, as defined(2)

  $ 792,253     $ 845,665     $ 631,970     $ 342,977     $ 194,384  

Capital expenditures, including capitalized interest

    457,515       487,937       487,482       182,207       124,488  

Acquisitions of businesses, net of cash acquired(3)

    44,260       80,449       2,412       709,575       (18 )

Net cash provided by operating activities

    694,660       637,483       215,913       230,922       453,362  

Net cash provided by (used in) investing activities, including capital expenditures(3)

    108,377       (576,977 )     (488,955 )     (889,680 )     (102,608 )

Net cash (used in) provided by financing activities

    (437,993 )     120,558       257,888       649,032       (296,773 )

 

   

At December 31,

 
   

2013

   

2012

   

2011

   

2010

   

2009

 

Balance Sheet Data:

                                       

Cash and cash equivalents

  $ 599,306     $ 253,172     $ 71,721     $ 96,350     $ 89,742  

Current assets held for sale(4)

    -       632,496       617,167       437,481       346,209  

Total current assets

    1,525,907       1,826,092       1,489,659       1,100,004       925,568  

Property, plant and equipment, net

    1,902,789       1,827,242       1,534,987       1,237,008       740,726  

Noncurrent assets held for sale(4)

    -       31,605       28,232       21,178       14,349  

Total assets

    4,131,261       4,439,962       3,703,641       3,015,999       1,932,386  

Long-term debt and capital leases, excluding current portion and 2 3/8% Notes

    972,692       1,279,805       971,621       731,732       8,215  

2 3/8% contingent convertible senior subordinated notes

    -       -       170,884       163,108       155,859  

Total stockholders' equity

    2,625,294       2,465,800       1,963,272       1,628,933       1,382,066  

 

__________

 

(1)

Our effective tax rate increased in 2009 due to the impairment of non-deductible goodwill.

 

(2)

The term EBITDA as defined consists of net income attributable to continuing operations plus interest expense, net, loss on extinguishment of debt, 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.

 

(4)

In September 2013, we sold our tubular services segment. The applicable assets and liabilities of this business have been classified as held for sale in the Consolidated Balance Sheets prior to December 31, 2013.

 

We believe that net income attributable to continuing operations 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 attributable to continuing operations, as derived from our financial information (in thousands):

 

   

Year Ended December 31,

 
   

2013

   

2012

   

2011

   

2010

   

2009

 

Net income attributable to Oil States International, Inc. - continuing operations

  $ 314,894     $ 401,518     $ 282,155     $ 139,375     $ 26,953  

Depreciation and amortization expense

    276,444       227,792       186,389       122,901       116,665  

Interest expense, net

    73,549       67,339       55,806       15,050       14,870  

Loss on extinguishment of debt

    7,374       -       -       473       -  

Income tax provision

    119,992       149,016       107,620       65,178       35,896  

EBITDA, as defined

  $ 792,253     $ 845,665     $ 631,970     $ 342,977     $ 194,384  

 

 
45

 

 

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

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains “forward-looking statements” 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 and well site services business segments, and our accommodations segment also supports the mining industry. 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 invest capital in the exploration for and development of oil, natural gas, met coal and other mineral reserves. Our customers’ capital spending programs 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 largely sensitive to expected commodity prices, principally related to crude oil, met coal and natural gas.

 

In the past few years, crude oil prices in North America have been volatile due to global economic uncertainties as well as inadequate regional take-away pipeline capacity. However, crude oil prices continue to trade at relatively high historic levels. This price volatility moderated in 2013 with some fluctuations in crude oil prices resulting from changing market sentiment regarding the outlook for economic growth in the U.S. and China, decreased crude oil production by Organization of the Petroleum Exporting Countries (OPEC), heightened geopolitical risks in the Middle East and North Africa and increased oil production in the U.S. The price of West Texas Intermediate (WTI) crude oil increased from an average price of $88 per barrel in the fourth quarter of 2012 to $98 per barrel in 2013, finishing 2013 at $98 per barrel. The price of Intercontinental Exchange (ICE) Brent crude decreased modestly from an average price of $110 per barrel in the fourth quarter of 2012 to $109 per barrel in 2013, finishing 2013 at $110 per barrel. As of February 19, 2014, WTI crude traded at approximately $103 per barrel while ICE Brent crude traded at approximately $110 per barrel. The price for WTI will influence our customers’ spending in U.S. shale play developments, such as the Bakken, Niobrara, and Eagle Ford, as well as the Permian Basin of Texas. Spending in these regions will influence the overall drilling and completion activity in the area and, therefore, the activity of our well site services segment.

 

In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Pricing for WCS is driven by several factors. A significant factor affecting WCS pricing is the underlying price for WTI. As WTI prices have improved over the past few years with the global economic recovery, WCS prices have also improved. Another significant factor affecting WCS pricing has been transportation. Historically, WCS has traded at a discount to WTI, creating a “WCS Basis Differential”, due to transportation costs and limited capacity to move growing Canadian heavy oil production to U.S. refineries. Depending on the extent of pipeline capacity availability, the WCS Basis Differential has varied. With the increase in global oil prices and increased transportation capacity from the oil sands region due to rail and barge alternatives, the absolute price of WCS has increased and the WCS Basis Differential has decreased. WCS prices in 2013 averaged $73.58 per barrel compared to $71.80 per barrel in 2012. However, the WCS Basis Differential widened substantially from below $15 per barrel to $25 per barrel as of February 19, 2014, as production increased and demand from U.S. refineries declined due to maintenance requirements. Should the price of WTI decline or the WCS Basis Differential widen further, our oil sands customers’ may delay additional investments or reduce their spending in the oil sands region.

 

 
46

 

 

Given the historical volatility of crude prices and the WCS discount, there remains a risk that prices could deteriorate going forward due to increased domestic crude oil production or slowing growth rates in China, fiscal and financial uncertainty in the U.S. and various European countries and a prolonged level of relatively high unemployment in the U.S. and other advanced economies. However, if the global supply of oil and global inventory levels were to decrease due to government instability in a major oil-producing nation 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 crude prices, which, coupled with an improvement in takeaway capacity from the oil sands, could improve WCS pricing. This, in turn, could lead to our oil sands customers increasing their investments in oil sands production. Conversely, if WCS crude prices continue to experience a significant discount to WTI crude, our oil sands customers may have an incentive to delay additional investments in their oil sands assets.

 

Prices for natural gas in the United States improved during 2013 and early 2014, largely due to above average storage withdrawals in response to colder than normal weather, continued elevated demand for natural gas for electric power generation, lower net imports from Canada and higher industrial demand. However, natural gas prices continue to be weak relative to prices experienced in 2006 through 2008 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 traded at approximately $6.04 per Mcf as of February 19, 2014. As a result of natural gas production growth outpacing demand in the U.S., the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 341 rigs as of February 14, 2014. Natural gas inventories in the U.S. have declined from being 12% above the 5-year average at the end of 2012 to 9% below the 5-year average at the end of 2013. 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.

 

Our Australian villages in the Bowen Basin primarily serve coal mines in that region. Met coal pricing and growth in production in the Bowen Basin region is influenced by levels of steel production. Because Chinese steel production has been growing at a slower pace than that experienced in 2010 and early 2011, Chinese demand for imported steel inputs such as met coal and iron ore decreased during 2013 compared to 2012. Met coal prices have decreased materially from over $200/metric ton at the beginning of 2012 to approximately $150/metric ton at the end of 2013. Depressed met coal prices have led to the implementation of cost control measures by our customers, some coal mine closures and delays in the start-up of new coal mining projects in Australia. A continued depressed met coal price will impact our customers’ future capital spending programs. However, steel consumption per capita in China is less than one-third of the amount installed in the U.S. economy, suggesting a favorable outlook for Chinese steel production and met coal demand over a longer horizon.

 

Recent WTI crude, ICE Brent crude, WCS crude, Queensland hard coking coal and natural gas pricing trends are as follows:

 

   

Average Price (1)

 

Quarter

ended

 

WTI

Crude

(per bbl)

   

ICE Brent

Crude

(per bbl)

   

WCS

Crude

(per bbl)

   

Hard

Coking Coal (Met Coal)

(per ton)

   

Henry Hub

Natural Gas

(per mcf)

 

12/31/2013

  $ 97.50     $ 109.23     $ 66.34     $ 143.76     $ 3.85  

9/30/2013

    105.83       110.23       83.10       142.21       3.55  

6/30/2013

    94.05       102.56       77.48       149.94       4.02  

3/31/2013

    94.33       112.47       66.86       167.71       3.49