Attached files

file filename
EX-32.2 - EXHIBIT 32.2 - OIL STATES INTERNATIONAL, INCois20171231_ex322.htm
EX-32.1 - EXHIBIT 32.1 - OIL STATES INTERNATIONAL, INCois20171231_ex321.htm
EX-31.2 - EXHIBIT 31.2 - OIL STATES INTERNATIONAL, INCois20171231_ex312.htm
EX-31.1 - EXHIBIT 31.1 - OIL STATES INTERNATIONAL, INCois20171231_ex311.htm
EX-24.1 - EXHIBIT 24.1 - OIL STATES INTERNATIONAL, INCois20171231_ex241.htm
EX-23.1 - EXHIBIT 23.1 - OIL STATES INTERNATIONAL, INCois20171231_ex231.htm
EX-21.1 - EXHIBIT 21.1 - OIL STATES INTERNATIONAL, INCois20171231_ex211.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, 2017
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 and zip code)
 
Registrant's telephone number, including area code is (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. [   ]
 
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
[   ]
 
 
 
 
 
 
 
 
Emerging growth company
[   ]
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [   ]
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [   ] No [X]
 
As of June 30, 2017, the aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $1,348,804,523.
 
As of February 16, 2018, the number of shares of common stock outstanding was 60,062,963.
 
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Definitive Proxy Statement for the 2018 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 
 
Item 1.
Business
 
Item 1A.
Risk Factors
 
Item 1B.
Unresolved Staff Comments
 
Item 2.
Properties
 
Item 3.
Legal Proceedings
 
Item 4.
Mine Safety Disclosures
 
 
 
 
PART II
 
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Item 6.
Selected Financial Data
 
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
Item 8.
Financial Statements and Supplementary Data
 
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
 
Item 9A.
Controls and Procedures
 
Item 9B.
Other Information
 
 
 
PART III
 
 
Item 10.
Directors, Executive Officers and Corporate Governance
 
Item 11.
Executive Compensation
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence
 
Item 14.
Principal Accounting Fees and Services
 
 
 
PART IV
 
 
Item 15.
Exhibits, Financial Statement Schedules
SIGNATURES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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PART I
 
Cautionary Statement Regarding Forward-Looking Statements
 
This Annual Report on Form 10-K and other statements we make contain 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.
 
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 relate to 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 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 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. The following are 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 of and demand for oil and natural gas;
fluctuations in the current and future prices of oil and natural gas;
the cyclical nature of the oil and gas industry;
the level of exploration, drilling and completion activity;
the financial health of our customers;
the availability of attractive oil and natural gas field prospects, which may be affected by governmental actions or actions of other parties which may restrict drilling;
the level of offshore oil and natural gas developmental activities;
general global economic conditions;
the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing;
global weather conditions and natural disasters;
changes in tax laws and regulations;
impact of environmental matters, including future environmental regulations;
our ability to find and retain skilled personnel;
negative outcome of litigation, threatened litigation or government proceeding;
fluctuations in currency exchange rates;
the availability and cost of capital;
our ability to complete and integrate acquisitions of businesses, including the ability to retain GEODynamics, Inc.'s customers and employees, to successfully integrate GEODynamics, Inc.'s operations, product lines, technology and employees into our operations, and achieve the expected accretion in earnings; and
the other factors identified in "Part I, Item 1A. Risk Factors."
 

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Should one or more of these risks or uncertainties materialize, or should the assumptions on which our forward-looking statements are based prove incorrect, actual results may differ materially from those expected, estimated or projected. In addition, the factors identified above may not necessarily be 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. 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.
 
In addition, in certain places in this Annual Report on Form 10-K, we refer to information and reports published by third parties that purport to describe trends or developments in the energy industry. The Company does so for the convenience of our stockholders and in an effort to provide information available in the market that will assist the Company’s investors to have a better understanding of the market environment in which the Company operates. However, the Company specifically disclaims any responsibility for the accuracy and completeness of such information and undertakes no obligation to update such information.
 
Item 1. Business
 
Our Company
 
Oil States International, Inc., through its subsidiaries, is a global oilfield products and services company serving the drilling, completion, subsea, production and infrastructure sectors of the oil and gas industry. Our manufactured products include highly engineered capital equipment as well as products consumed in the drilling, well construction and production of oil and gas. We are also a leading provider of completion services to the industry. Through our recent acquisition of GEODynamics, Inc. ("GEODynamics"), we are a leading researcher, developer and manufacturer of engineered solutions to connect the wellbore with the formation in oil and gas well completions. Oil States is headquartered in Houston, Texas with manufacturing and service facilities strategically located across the globe. Our customers include many national oil and natural gas companies, major and independent oil and natural gas companies, onshore and offshore drilling companies and other oilfield service companies. Prior to our acquisition of GEODynamics in January 2018, we operated through two business segments – Offshore/Manufactured Products and Well Site Services – and have established a leadership position in certain of our product or service offerings in each segment. The GEODynamics operations will be reported as a separate business segment beginning in the first quarter of 2018 under the name “Downhole Technologies.” In this Annual Report on Form 10‑K, references to the "Company" or “Oil States” or to "we," "us," "our," and similar terms are to Oil States International, Inc. and its consolidated subsidiaries.
 
Available Information
 
The Company’s Internet website is www.oilstatesintl.com. The Company makes available free of charge through its website its Annual Report on Form 10‑K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8‑K, its proxy statement, Forms 3, 4 and 5 filed on behalf of directors and executive officers, 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 “SEC”). The Company is not including the information contained on the Company's website or any other website as a part of, or incorporating it by reference into, this Annual Report on Form 10‑K or any other filing the Company makes with the SEC. The filings are also available through the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Additionally, these filings are available on the Internet at 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 & 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 provided to stockholders without 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 historically grown our product and service offerings organically, through capital spending, and also through strategic acquisitions. Our investments are focused in growth areas and on areas where we expect to be able to expand market share through technology and where we believe we can achieve an attractive return on our investment. As part of our long-term strategy, we continue to review complementary acquisitions as well as make organic capital expenditures to enhance our cash flows and increase our stockholders’ 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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Recent Developments
 
Acquisitions of other oilfield service businesses have been an important aspect of our growth strategy and plan to increase stockholder value. Our acquisition strategy has historically allowed us to leverage our existing and acquired products and services into new geographic locations, and has expanded our technology and product offerings.
 
During 2017, we acquired, as part of our Offshore/Manufactured Products segment, complementary intellectual property and assets to expand our global crane manufacturing and service operations as well as our riser testing, inspection and repair service offerings.
 
In addition, on December 12, 2017 we entered into an agreement to acquire GEODynamics, which provides oil and gas perforation systems and downhole tools in support of completion, intervention, wireline and well abandonment operations.
 
On January 12, 2018, we closed the acquisition of GEODynamics for total consideration of approximately $615 million (the "GEODynamics Acquisition"). For the years ended December 31, 2017 and 2016, GEODynamics generated $166.4 million and $72.1 million of revenues, respectively, and $24.4 million and $0.1 million of net income, respectively.
 
Following the close of the GEODynamics Acquisition, we completed several financing transactions to extend the maturity of our debt while providing us with the flexibility to repay outstanding borrowings under our revolving credit facility with anticipated future cash flows from operations.
 
On January 30, 2018, we sold $200.0 million aggregate principal amount of our 1.50% convertible senior notes due 2023 (the “Notes”) through a private placement to qualified institutional buyers. We received net proceeds from the offering of the Notes of approximately $194.0 million, after deducting fees and estimated expenses. We used the net proceeds from the sale of the Notes to repay a portion of the borrowings outstanding under our revolving credit facility (the "Revolving Credit Facility"), substantially all of which were drawn to fund the cash portion of the purchase price of the GEODynamics Acquisition.
 
Concurrently with the Notes offering, we amended our Revolving Credit Facility (the “Amended Revolving Credit Facility”), to extend the maturity date to January 2022, permit the issuance of the Notes and provide for up to $350.0 million in borrowing capacity.
 
See Note 18, “Subsequent Events,” to the Consolidated Financial Statements included in this Annual Report on Form 10‑K for further discussion of these recent developments.
 
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. See Note 15, "Segments and Related Data," to the Consolidated Financial Statements included in “Part II, Item 8. Financial Statements and Supplementary Data” for financial information by segment along with a geographical breakout of revenues and long-lived assets for each of the three years in the period ended December 31, 2017. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and natural gas industry, particularly our customers' willingness to invest capital on the exploration for and development of crude oil and natural gas resources. 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 expectations with respect to future crude oil and natural gas prices.
 
Our historical financial results reflect the cyclical nature of the oilfield services industry – witnessed by periods of increasing and decreasing activity in each of our operating segments. A severe industry downturn started in the second half of 2014 and continued into 2017. This prolonged industry downturn has been characterized by materially reduced capital investments made by our customers, lower rig counts, lower crude oil prices and other negative industry events. The industry decline was very rapid in the U.S. shale plays given the general lack of long-term contracts or backlog in these regions of operations. The U.S. rig count declined 79% from the peak in 2014 before bottoming in May of 2016. While the average U.S. rig count increased 71% in 2017 from the 2016 average, activity levels in 2017 were still well below 2014 levels. This significant activity decline continued to have a material negative effect on the results of our Well Site Services segment, before beginning to recover in the second half of 2017. Our Offshore/Manufactured Products segment was also negatively impacted by the industry downturn but our results declined at a slower pace given higher levels of backlog that existed at the beginning of 2014. Despite an initially slower decline in revenues and operating income when compared to our Well Site Services segment, our Offshore/Manufactured Products backlog declined materially from 2014 to 2017, which negatively impacted our results, particularly those tied to major projects. For additional information about activities in each of our segments, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Demand for the products and services supplied by our Offshore/Manufactured Products segment is generally driven by the longer-term outlook for commodity prices and changes in land-based drilling and completion activity. During 2013 and 2014, we benefited from high crude oil prices resulting in very active bidding and quoting activity for our Offshore/Manufactured Products segment. However, the decline in crude oil prices that began in 2014 and continued into 2017, coupled with the relatively uncertain outlook around shorter-term and possibly longer-term pricing improvements have caused exploration and production companies to reevaluate their future capital expenditures in regards to deepwater projects since they are expensive to drill and complete, have long lead times to first production and may be considered uneconomical relative to the risk involved. Bidding and quoting activity for our Offshore/Manufactured Products segment continued after 2014, albeit at a substantially slower pace.
 
Our Well Site Services segment is primarily affected by drilling and completion activity in the United States, including the Gulf of Mexico, and, to a lesser extent, Canada and the rest of the world. U.S. drilling and completion activity and, in turn, our Well Site Services results, are particularly sensitive to near-term fluctuations in commodity prices given the call-out nature of our operations in the segment. While there has been notable improvement in 2017, our Well Site Services segment continues to be significantly negatively affected by the material decline in crude oil prices since 2014.
 
Over recent years, our industry experienced increased customer spending in crude oil and liquids-rich exploration and development in the North American shale plays utilizing horizontal drilling and completion techniques. According to rig count data published by Baker Hughes, a GE company ("Baker Hughes"), the U.S. oil rig count peaked in October 2014 at 1,609 rigs but has declined materially since late 2014 due to much lower crude oil prices, totaling 747 rigs as of December 31, 2017 (with the U.S. oil rig count having troughed at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of December 31, 2017, oil-directed drilling accounted for 80% of the total U.S. rig count - with the balance natural gas related. The U.S. natural gas-related working rig count declined from 810 rigs at the beginning of 2012 to 81 rigs in August of 2016, a more than 29 year low. Total U.S. rig count has increased 525 rigs, or 130%, since troughing in May of 2016, largely due to improved crude oil prices, decreased service costs and improved technologies applied in the shale play regions of the United States.
 
See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Macroeconomic Environment.”
 
Offshore/Manufactured Products
 
Overview
 
For the years ended December 31, 2017, 2016 and 2015, our Offshore/Manufactured Products segment generated approximately 57%, 73% and 66%, respectively, of our revenue and 73%, 94% and 74%, respectively, of our gross profit (revenues less cost of products and services). Through this segment, we provide highly-engineered products and services for offshore oil and natural gas production systems and facilities, as well as certain products and services to the offshore and land-based drilling and completion markets. Our products and services used primarily in deepwater producing regions include our FlexJoint® technology, advanced connector systems, high-pressure riser systems, compact valves, deepwater mooring systems, cranes, subsea pipeline products, specialty welding, fabrication, cladding and machining services, offshore installation services and inspection and repair services. In addition, we design, manufacture and market numerous other products and services used in land and offshore drilling and completion activities and by non-oil and gas customers, including consumable downhole elastomer products utilized in onshore completion activities, valves and sound and vibration dampening products. We have facilities that support our Offshore/Manufactured Products segment in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Oklahoma City and Tulsa, Oklahoma; the United Kingdom; Brazil; Singapore; Thailand; Vietnam; China; the United Arab Emirates; and India.
 
Offshore/Manufactured Products Market
 
The market for Offshore/Manufactured Products centers primarily on the development of infrastructure for offshore production facilities and their subsequent operations, exploration and drilling activities, and to a lesser extent, new rig and vessel construction, refurbishments or upgrades. 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. Sales of our shorter-cycle products to land-based drilling and completion markets is driven by the level and complexity of drilling, completion and workover activity, particularly in North America.
 

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Products and Services
 
In operation for more than 75 years, our Offshore/Manufactured Products segment provides a broad range of products and services for use in offshore development and drilling activities. This segment also provides products for onshore oil and natural gas, defense and general industries. Our Offshore/Manufactured Products segment is dependent in part on the industry's continuing innovation and creative applications of existing technologies. We own various patents covering some of our technology, particularly in our connector and valve product lines.
 
Offshore Development and Drilling Activities. We design, manufacture, fabricate, inspect, assemble, repair, test and market OEM equipment for mooring, pipeline, production and drilling risers, and subsea applications along with equipment for offshore vessel and rig construction. 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 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 joints;
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;
consumable downhole products; and
other products and services, including welding, cladding and other metallurgical technologies.
 
Flexible Bearings and Advanced Connection Systems. We are the key supplier of flexible bearings, or FlexJoint® connectors, to the offshore oil and natural 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 allows for rotational movement of a riser or tension leg platform tether while under high tension and/or pressure. When positioned at the top, bottom and, in some cases, middle of a deepwater riser, it reduces the stress and loads on the riser while compensating for the pitch and rotational forces on the riser as the production facility or drilling rig moves with ocean forces. FlexJoint® connectors are used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water. Drilling riser systems provide the vertical conduit between the floating drilling vessel and the subsea wellhead. Through the drilling riser, the drill string 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 facility. Oil and natural gas flows to the surface for processing through the production riser. Export risers provide the vertical conduit from the floating production facility to the subsea export pipelines. Our FlexJoint® connectors 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 (defined below) 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 tether joints 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® connectors are used to attach the various production, injection, import or export risers to all of these floating production systems.
 
Casing and Conductor Connections and Joints. 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 machined onto plain-end-pipe. Our connectors are reusable and pliable and depending on the application are equipped with 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).

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These flexible bearings and advanced connector systems are primarily manufactured through our Arlington, Texas, United Kingdom 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 Valve 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.
 
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 as well as 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, blow-out preventer handling equipment, as well as handling equipment used in the installation of offshore wind turbine platforms. 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 provided through 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 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 20,000 psi) riser systems used in high-fatigue, deepwater applications. Our riser systems are designed to meet a range of static and fatigue stresses on par with those of our Tension Leg Element (“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. We believe that

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our marine riser offers superior 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 not typically a manufacturer of BOP components, we design and fabricate lifting and protection frames for BOP stacks and offer the complete system integration of BOP 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, United Kingdom, Singapore and Brazil locations.
 
Consumable Downhole Products. North American shale play development has expanded the need for more advanced completion tools. To reduce well completion costs, minimizing the time to drill out tools is very important. Offshore/Manufactured Products has leveraged its knowledge of molded thermoset composites and elastomers to help meet this demand. For example, we have had success in developing and producing composite drillable zonal isolation tools (i.e., bridge/frac plugs) utilizing design and production techniques that reduce cost while still delivering high quality performance. Time to drill out has been reduced significantly in comparison to other filament wound products in the market. Our products also include:
 
Swab Cups - used primarily in well servicing work;
Rod Guides/Centralizers - used in both drilling and production for pipe protection;
Gate Valve and Butterfly Valve Seats – we service many markets in the valve industry including well completion, refining, and distribution;
Casing and Cementing Products – we are a custom manufacturer of cementing plugs, well bore wipers, valve assemblies, combination plugs, specialty seals and gaskets; and
Service Tools – our products include frac balls, packer elements, zonal isolation tools, as well as many custom molded products used in the well servicing industry.
 
Other Products & Services. Our Offshore/Manufactured Products segment also produces a variety of products for use in industrial, military and other applications outside the oil and gas industry. For example, we provide:
 
sound and vibration isolation equipment for marine vessels;
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. Offshore/Manufactured Products’ backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. Backlog in our Offshore/Manufactured Products segment was $168 million at December 31, 2017, compared to $199 million at December 31, 2016 and $340 million at December 31, 2015. We expect approximately 80% of our backlog at December 31, 2017 to be recognized as revenue during 2018. 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. While backlog cancellations have historically been insignificant, we incurred cancellations totaling $3.5 million during 2017 and $3.7 million during 2016, which we believe is attributable to lower commodity prices, the resultant decrease in capital spending by our clients and, in some cases, the financial condition of our customers. Additional cancellations may occur in the future, further reducing our backlog. Our backlog is an important indicator of future Offshore/Manufactured Products’ shipments and revenues; however, backlog as of any particular date may not be indicative of our actual operating results for any future period. We believe that the offshore construction and development business is characterized by lengthy projects and a long "lead-time" order cycle. The change in backlog levels from one period to the next does not necessarily evidence a long-term trend.
 
Regions of Operations
 
Our Offshore/Manufactured Products segment provides products and services to customers in the major offshore crude oil and natural gas producing regions of the world, including the U.S. Gulf of Mexico, Brazil, West Africa, the North Sea, Azerbaijan, Russia, India, Southeast Asia, China, the United Arab Emirates and Australia. In addition, we provide shorter-cycle products to customers in the land-based drilling and completion markets in the United States and, to a lesser extent, outside the United States.
 

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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. While no customer accounted for more than 10% of our consolidated revenues in 2015 or 2016, Halliburton Company individually accounted for 16% of our total consolidated revenues in the year ended December 31, 2017. Our main competitors in this segment include Cameron (a division of Schlumberger Limited), TechnipFMC plc, Dril-Quip, Inc., National Oilwell Varco, Inc., Baker Hughes, Hutchinson Group (a subsidiary of Total), Sparrows Offshore Group LTD, Oceaneering International, Inc. and Raina Engineers.
 
Well Site Services
 
Overview
 
For the years ended December 31, 2017, 2016 and 2015, our Well Site Services segment generated approximately 43%, 27% and 34%, respectively, of our revenue and 27%, 6% and 26%, respectively, of our gross profit (revenues less costs of products and services). 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 life cycle. In this segment, our operations primarily 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 cycle.
 
Well Site Services Market
 
Demand for our completion and drilling services is predominantly tied to the level of oil and natural gas exploration and production activity on land in the United States. The primary driver for this activity is the price of crude oil and, to a lesser extent, 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;
downhole extended-reach technology;
pipe recovery systems;
thru-tubing milling and fishing services;
hydraulic chokes and manifolds;
blow out preventers; and
gravel pack and sand control 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, 2017, we provided completion services through approximately 40 distribution locations serving the United States, including the Gulf of Mexico, Canada and other international markets. We consolidated 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. No customer represented more than 10% of our total consolidated revenue in any period presented. Competition in the Completion Services

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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, provides land drilling services in the United States for shallow to medium depth wells generally of less than 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, 2017, we had thirty-four drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds. 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 87% in 2014 to an average 12% in 2016 due to lower crude oil and natural gas prices and a shift by customers to newer, larger and higher horsepower rigs needed to drill extended depths and horizontal wells. During 2017, utilization of our drilling rigs increased to an average of 29%, largely due to improved crude oil prices. We believe commodity prices should improve over the longer-term but there will be fewer wells in our depth range which could influence overall utilization of our drilling rigs.
 
We market our Drilling Services directly to a diverse customer base, consisting primarily of 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. 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.
 
Seasonality of Operations
 
Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in the Rocky Mountain region, the Gulf of Mexico and Canada. Severe winter weather conditions in the Rocky Mountain region can restrict access to work areas for our Well Site Services 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 levels of activity in the winter months. 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. A portion of our Completion Services operations in Canada is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. 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.
 
Employees
 
As of December 31, 2017, the Company employed 3,077 full-time employees on a consolidated basis, 50% of whom are in our Offshore/Manufactured Products segment, 47% of whom are in our Well Site Services segment and 3% of whom are in our corporate headquarters. This compares to a total of 2,821 full-time employees as of December 31, 2016. Company-wide headcount was reduced by approximately 42% between December 31, 2014 and December 31, 2017 in response to weak industry conditions. We were party to collective bargaining agreements covering a small number of employees located in Argentina and the United Kingdom as of December 31, 2017. We believe we have good labor relations with our employees.
 
Environmental and Occupational Health and Safety Matters
 
Our business operations are subject to numerous federal, state, local, tribal and foreign environmental and occupational health and safety laws and regulations. Numerous governmental entities, including domestically the U.S. Environmental Protection Agency (“EPA”), the federal Bureau of Alcohol, Tobacco, Firearms and Explosives ("ATF"), the U.S. Occupational Safety and Health Administration ("OSHA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) impose stringent regulations on the licensing or storage and use of explosive; (v) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi) impose specific safety and health criteria addressing worker protection; and (vii) impose substantial liabilities for pollution resulting from drilling operations and well site support services.

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The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. laws and regulations, as amended from time to time:
 
the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas emissions (“GHGs”);
the Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
the Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States;
U.S. Department of the Interior regulations, which relate to offshore oil and natural gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages;
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;
the Safe Drinking Water Act (“SDWA”), which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;
the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;
the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;
the National Environmental Policy Act, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment;
the Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials, including explosives, and emergency response preparedness; and
regulations adopted by the ATF, a law enforcement agency under the U.S. Department of Justice, that impose stringent licensing conditions with respect to the acquisition, storage and use of explosives for use in well site support services in the oil and natural gas sector.
 
These U.S. laws and regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Additionally, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in place of the government and sue operators for alleged violations of environmental law. See Risk Factors under Part I, Item 1A of this Form 10‑K for further discussion on hydraulic fracturing; ozone standards, induced seismicity regulatory developments; climate change, including methane or other GHG emissions; storage and use of explosives; offshore drilling and related regulatory developments, including with respect to decommissioning obligations; and other regulations relating to environmental protection. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.
 

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Many states where we operate also have, or are developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. In addition, many foreign countries where we are conducting business also have, or may be developing, regulatory initiatives or analogous controls that regulate our environmental or occupational safety-related activities. While the legal requirements imposed under state or foreign law may be similar in form to U.S. laws and regulations, in some cases the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development or expansion of a project or substantially increase the cost of doing business. In addition, environmental and occupational health and safety laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental or worker health and safety concerns, are expected to continue to have an increasing impact on our and our oil and natural gas exploration and production customers’ operations.
 
We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results. Although we are not fully insured against all environmental and occupational health and safety risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe is sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental and occupational health and safety laws and regulations, claims for damages to property or persons or disruption of our customers' operations resulting from our operations, and imposition of penalties could have a material adverse effect on us and our results of operations.
 
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.
 
Demand for most of our products and services is substantially dependent on the levels of expenditures by companies in the oil and natural gas industry. Low oil and natural gas prices have significantly reduced the demand for our products and services and the prices we are able to charge. This has had and may continue to have a material adverse effect on our financial condition and results of operations.
 
Demand for most of our products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The significant decline in oil and natural gas prices during 2015 that continued in 2016 and 2017 caused a reduction in most of our customers’ drilling, completion and other production activities and related spending on our products and services. The reduction in demand from our customers has resulted in an oversupply of many of the services and products we provide, and such oversupply has substantially reduced the prices we can charge our customers for many of our products and services. Although oil and natural gas prices improved somewhat since the trough in 2016, these price improvements have not resulted in global improvements in the demand for our products and services or the prices we are able to charge. If oil and natural gas prices remain depressed or decline, our customers’ activity levels and spending, and the prices we charge, may remain depressed and could worsen. In addition, a continuation or worsening of these conditions may result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in the collection of amounts owing to us and similar impacts. These conditions have had and may continue to have an adverse impact on our financial condition, results of operations and cash flows, and it is difficult to predict how long the current depressed commodity price environment will continue.
 
Although conditions in our industry improved in 2017, particularly in the shale resource plays in the United States, they must continue to improve or we could encounter difficulties such as an inability to access needed capital on attractive terms or at all, the incurrence of asset impairment charges, the inability to meet financial ratios contained in our debt agreements, the need to reduce our capital spending and other similar impacts. For example, our reduced EBITDA during recent periods resulted in our inability to access the full borrowing capacity available under our Revolving Credit Facility during those periods as a result of the maximum leverage ratio covenant, which under our Amended Revolving Credit Facility, requires that our ratio of total net debt to consolidated EBITDA be no greater than 4.00 to 1.0 for fiscal quarters ending prior to December 31, 2018 and no greater than 3.75 to 1.0 thereafter. As more fully disclosed in Note 18, "Subsequent Events," in the Notes to the Consolidated Financial Statements, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Liquidity, Capital Resources and Other Matters,” we discuss our expectations regarding liquidity and covenant compliance for 2018.
 

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Many factors affect the supply of and demand for oil and natural gas and, therefore, influence product prices, including:
the level of drilling activity;
the level of oil and natural gas production;
the levels of oil and natural gas inventories;
depletion rates;
worldwide demand for oil and natural gas;
the expected cost of finding, developing and producing new reserves;
delays in major offshore and onshore oil and natural gas field development timetables;
the 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 and natural gas, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
global weather conditions and natural disasters;
worldwide economic activity including growth in developing countries;
national government political requirements, including the ability and willingness of 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;
shareholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
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 liquefied natural gas or alternative fuels;
environmental and other governmental laws and regulations; and
domestic and foreign tax policies.
 
The recent oversupply of oil and natural gas relative to demand resulted in significantly lower oil and natural gas prices beginning in the second half of 2014 which continued through much of 2017. As a result, many of our customers reduced or delayed their capital spending, which reduced the demand for our products and services and exerted downward pressure on the prices paid for our products and services. Although some of our customers have increased their 2018 capital expenditure budgets, these customers are still spending significantly less than their pre-2015 levels. Additionally, if oil and natural gas prices decline, these customers may further reduce their spending levels. We expect that we will continue to encounter weakness in the demand for, and prices of, our products and services until commodity prices stabilize at higher levels and our customers’ capital spending increases. Any prolonged reduction in the overall level of exploration and production activities, whether resulting from changes in oil and natural gas prices or otherwise, could materially adversely affect our financial condition, results of operations and cash flows in many ways including by negatively affecting:
our equipment utilization, revenues, cash flows and profitability;
our ability to obtain additional capital to finance our business and the cost of that capital; and
our ability to attract and retain skilled personnel.
 

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Given the cyclical nature of our business, a severe prolonged downturn could negatively affect the value of our goodwill.
 
As of December 31, 2017, goodwill represented 21% of our total assets, and we expect to record substantial additional goodwill in connection with the GEODynamics Acquisition. We record goodwill when the consideration we pay in acquiring a business exceeds the fair market value of the tangible and separately measurable intangible net assets of that business. We are required to periodically review the goodwill of our applicable reporting units (currently, Completion Services and Offshore/Manufactured Products) for impairment in value and to recognize a non-cash charge against earnings causing 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 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 further 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.
 
Federal, state and local 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 that may reduce demand for our products and services and could have a material adverse effect on our business, results of operations and financial condition.
 
Although we do not directly engage in hydraulic fracturing, a material portion of our Completion Services and Offshore/Manufactured Products operations support many of our oil and natural gas exploration and production customers in such activities. Hydraulic fracturing is an important and commonly used process for the completion of oil and natural gas wells in formations with low permeability, such as shale formations, and involves the pressurized injection of water, sand or other proppants and chemical additives into rock formations to stimulate production. Hydraulic fracturing is currently generally exempt from regulation under the Safe Drinking Water Act’s (the “SDWA”) Underground Injection Control (“UIC”) program and is typically regulated in the United States by state oil and natural gas commissions or similar agencies.
 
However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the U.S. Environmental Protection Agency (“EPA”) asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. The EPA also issued Clean Air Act (“CAA”) final regulations in 2012 and in June 2016 governing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing; published an effluent limit guideline final rule in June 2016 prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and published an Advance Notice of Proposed Rulemaking in May 2014 regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (“BLM”) published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, a legal challenge to the BLM’s rescission of the 2015 rule was filed in federal court. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing in the United States 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, including states where we or our customers operate. States could also elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Additionally, local governments 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 December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge

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of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. 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 of which could reduce demand for the products and services of each of our business segments and have a material adverse effect on our business, financial condition, and results of operations.
 
The explosion of dangerous materials used in our recently acquired Downhole Technologies business, could disrupt our operations and could adversely affect our financial results.

Our business operations involve the licensing, storage and handling of explosive materials that are used in our Downhole Technologies business, which we acquired in the GEODynamics Acquisition in January 2018. Despite our use of specialized facilities to store and handle dangerous materials and our employee training programs, the storage and handling of explosive materials could result in incidents that temporarily shut down or otherwise disrupt our or our customers’ operations or could cause delays in the delivery of our services. It is possible that such an explosion could result in death or significant injuries to employees and others. Material property damage to us, our customers and third parties arising from an explosion or resulting fire could also occur. Any explosion could expose us to adverse publicity or liability for damages or cause production delays, any of which could have a material adverse effect on our operating results, financial condition and cash flows. Moreover, failure to comply with applicable requirements or the occurrence of an explosive incident may also result in the loss of our license to store and handle explosives, which would have a material adverse effect on our business, results of operations and financial conditions.

Federal or state legislative and regulatory initiatives related to induced seismicity could result in operating restrictions or delays in the drilling and completion of oil and natural gas wells that may reduce demand for our products and services and could have a material adverse effect on our business, results of operations and financial condition.
 
Our oil and natural gas producing customers dispose of flowback water or certain other oilfield fluids gathered from oil and natural gas producing operations in accordance with permits issued by government authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near underground disposal wells used for the disposal by injection of flowback water or certain other oilfield fluids resulting from oil and natural gas activities. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region and local geology, and that only a small fraction of injection wells in North America have been considered to be a potential cause of, or otherwise linked to, induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma has issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has adopted similar rules. In addition, another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by our customers to dispose of flowback water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition, including litigation, to oil and natural gas activities utilizing injection wells for waste disposal. Any one or more of these developments may result in our customers having to limit disposal well volumes, disposal rates or locations, or require our customers or third party disposal well operators that are used to dispose of customers’ wastewater to shut down disposal wells, which developments could adversely affect our customers’ business and result in a corresponding decrease in the need for our products and services, which could have a material adverse effect on our business, financial condition, and results of operations.
 
Additional domestic and international deepwater drilling laws, regulations and other restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.
 
In recent years, the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), each an agency of the U.S. Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory

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requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
 
Moreover, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional delays, restrictions or obligations with respect to oil and natural gas exploration and production operations conducted offshore. For example, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on federal Outer Continental Shelf (“OCS”) waters including in the Central Gulf of Mexico. BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-use and right-of-way applications. The proposed rule would bolster existing air emission requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare that, depending on the results obtained, could result in subsequent rulemakings that restrict offshore air emissions. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the amount of financial assurance required, the revised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our customers’ operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, and limit activities in certain areas, or cause our customers to incur penalties, fines, or shut-in production at one or more of our facilities or result in the suspension or cancellation of leases, which could reduce demand for our products and services. We may incur penalties directly from BSEE if, based on review of the facts surrounding an alleged violation upon an offshore lease, BSEE seeks to hold contractors, including contractors such as us who are involved in well completion operations, potentially liable for alleged violations of law arising in the BSEE’s jurisdiction area. While the Trump Administration has generally indicated an interest in scaling back or rescinding regulations that inhibit the development of the U.S. oil and gas industry, it is difficult to predict the extent to which such policies will be implemented or the outcome of any litigation challenging such implementation. Also, if material spill events were to occur in the future, the United States or other countries where such an event were to occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which developments could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws, regulations or legal initiatives on our customers’ drilling operations or on the cost or availability of insurance to cover the risks associated with such operations. The matters described above, individually or in the aggregate, could have a material adverse effect on our business, results of operations, financial condition, and liquidity.
 
We do business in international jurisdictions which exposes us to unique risks.
 
A portion of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 18% (9% excluding the United Kingdom and Canada) of our consolidated revenue in the year ended December 31, 2017. 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;
economic or trade sanctions;
changing foreign and domestic monetary and trade policies;

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changes in trade activity;
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.
 
As an illustration of this risk, there is a current recessionary economic environment in Brazil which, at present, is having a negative impact on orders and future growth prospects for the Company’s operations in Brazil. Sales to customers in Brazil accounted for approximately 2%, 6% and 5% of the Company’s consolidated revenues in 2017, 2016 and 2015, respectively.
 
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.
 
The U.S. Foreign Corrupt Practices Act (the “FCPA”), and similar anti-bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices and impact our business. Any failure to comply with the FCPA or other anti-bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operations. We could also face fines, sanctions, and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in, or curtailment of, business operations in those jurisdictions and the seizure of assets. Additionally, we may have competitors who are not subject to the same ethics-related laws and regulations which provides them with a competitive advantage 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.
 
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. 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.
 
The results of the United Kingdom’s referendum on withdrawal from the European Union including the subsequent exchange rate fluctuations and political and economic uncertainties may have a negative effect on global economic conditions, financial markets and our business.
 
We are a multinational company and are subject to the risks inherent in doing business in other countries, including the United Kingdom (the “U.K.”). In June 2016, a majority of voters in the U.K. elected to withdraw from the European Union in a national referendum (“Brexit”). The referendum was advisory, and the terms of any withdrawal are subject to a negotiation period that could last at least two years after the government of the U.K. formally initiates a withdrawal process. Nevertheless, Brexit has created significant uncertainty about the future relationship between the U.K. and the European Union and other countries, including with respect to the laws and regulations that will apply as the U.K. determines which European Union derived laws to replace or replicate in the event of a withdrawal. The referendum has also given rise to calls for the governments of other European Union member states to consider withdrawal. These developments, or the perception that any of these developments may occur, could potentially disrupt the markets we serve and the jurisdictions in which we operate and may cause us to lose customers, suppliers and employees.
 

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The impact from Brexit on our business and operations will depend on the outcome of tariff, tax treaty, trade, regulatory and other negotiations, as well as the impact of the withdrawal on macroeconomic growth and currency volatility, which are uncertain at this time. Any of these effects of Brexit could have a material adverse effect on our business, financial condition and results of operations.
 
We are subject to environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our operations are significantly affected by numerous federal, state, local, tribal and foreign 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 legal requirements. If existing regulatory requirements or enforcement policies change, we or our oil and natural gas exploration and production customers may be required to make significant, unanticipated capital and operating expenditures. Examples of recent regulations or other regulatory initiatives include the following:
Ground-Level Ozone Standards.    In October 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA issued geographical attainment designations in November 2017 and is expected to issue final non-attainment area requirements pursuant to this NAAQS rule in the first half of 2018. Any designations or requirements that result in reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our or our oil and natural gas exploration and production customers’ operations.
EPA Review of Drilling Waste Classification.    Drilling, fluids, produced water and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the Resource Conservation and Recovery Act (“RCRA”) and instead, are regulated under RCRA’s less stringent non-hazardous waste provisions. However, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.
Waters of the United States.    In May 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) released a final rule outlining federal jurisdictional reach under the Federal Water Pollution Control Act (“Clean Water Act”) over waters of the United States, including wetlands but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our customers could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
 

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Compliance with these regulations and other regulatory initiatives, or any other new environmental laws and regulations could, among other things, require us or our customers to install new or modified emission controls on equipment or processes, incur longer permitting timelines, and incur significantly increased capital expenditures and operating costs, which costs may be significant. Additionally, one or more of these developments could reduce demand for our products and services. Moreover, 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/or 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.
 
Our business activities present risks of incurring significant 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. Additionally, private parties, including the owners of properties upon which we perform services and facilities where our wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Some environmental laws and regulations may impose strict liability, which means that in some situations we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Remedial costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our liquidity, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance.
 
Climate change legislation and regulations restricting or regulating emissions of GHGs could result in increased operating and capital costs and reduced demand for our products and services.
 
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.
 
At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the federal Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our producing customers’ operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry.
 
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified or reconstructed facilities in the oil and natural gas source category that will require the use of certain equipment specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring, and leaking on federal and Indian lands. However, in December 2017, the BLM published a final rule that temporarily suspends or delays certain requirements contained in the November 2016 final rule until January 17, 2019. The suspension of the November 2016 final rule is being challenged in court. These rules, should they remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that requires member countries to review and “represent

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a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
 
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions imposed on us or our customers operations, 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 products and services. Any one or more of these developments could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Finally, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.
 
The Endangered Species Act and Migratory Bird Treaty Act (“ESA”) and other restrictions intended to protect certain species of wildlife govern our and our oil and natural gas exploration and production customers’ operations and additional restrictions may be imposed in the future, which constraints could have an adverse impact on our ability to expand some of our existing operations or limit our customers’ ability to develop new oil and natural gas wells.
 
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
 
Moreover, as a result of one or more settlements approved by the United States federal government, the U.S. Fish and Wildlife Service must make determinations on the listing of numerous species as endangered or threatened under the ESA. The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our oil and natural gas exploration and production customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas.
 
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 the Rocky Mountain region of the United States, the Gulf of Mexico and Canada. Severe winter weather conditions in the Rocky Mountain region of the United States can restrict access to work areas for our Well Site Services segment customers. Our operations in and near 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 levels of activity in the winter months. 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. 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.
 
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.
 

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Our inability to control the inherent risks of identifying 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 will continue to be, a key element of our growth strategy. We continually review complementary acquisition opportunities and we expect to seek to consummate acquisitions of such businesses in the future. However, we may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future or at all. In addition, 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, and the issuance of additional equity securities could result in significant dilution to stockholders.
 
We expect to gain certain business, financial, and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize these intended benefits. However, our inability to realize expected financial performance and strategic advantages as a result of an acquisition, including the GEODynamics Acquisition, could negatively affect the anticipated benefits of the acquisition. Additional risks we could face in connection with acquisitions, including the GEODynamics Acquisition, include:
retaining key employees and customers of acquired businesses;
retaining supply and distribution relationships key to the supply chain;
increased administrative burden, including additional costs associated with regulatory compliance;
diversion of management time and attention;
developing our sales and marketing capabilities;
managing our growth effectively;
potential goodwill impairment resulting from the overpayment for an acquisition;
integrating operations, workforce, product lines and technology;
managing tax and foreign exchange exposure;
operating a new line of business;
increased logistical problems common to large, expansive operations;
inability to pursue and protect patents covering acquired technology;
addition of acquisition-related debt and increased expenses and working capital requirements;
substantial accounting charges for restructuring and related expenses, write-off of in-process research and development, impairment of goodwill, amortization of intangible assets, and stock-based compensation expense;
becoming subject to unanticipated liabilities of the acquired business, including litigation related to the acquired business; and
achieving the expected benefits from the acquisition, including certain cost savings and operational efficiencies or synergies.
 
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 stockholders 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.
 
As a private company, the audit of GEODynamics’ financials was performed under the requirements of the American Institute of Certified Public Accountants rather than the Public Company Accounting Oversight Board and GEODynamics was not subject to the Sarbanes-Oxley Act of 2002.
 
As a company with securities registered under the Exchange Act, our consolidated financial statements included in our periodic filings with the SEC are required to be audited by independent registered public accountants who are subject to oversight by, and independent under the rules of, the Public Company Accounting Oversight Board (the “PCAOB”). As a private company before the GEODynamics Acquisition, GEODynamics was not subject to these requirements. As such, at the time of the audit report relating to GEODynamics filed by us on Form 8-K with the SEC, GEODynamics’ independent auditor did not meet the heightened standards otherwise required for auditing firms of public companies by the PCAOB.
 

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In addition, before we acquired it, GEODynamics was not subject to the Sarbanes-Oxley Act of 2002. We are currently evaluating the strength of GEODynamics’ internal control processes over financial reporting. As a smaller private company, GEODynamics did not operate under a fully documented system for accounting and internal control over financial reporting before we acquired it, and we may need to implement enhancements with respect to its internal controls over financial reporting.
 
Although we believe the financial information with respect to GEODynamics to be reliable, it is possible that adjustments to this financial information would have been made if the consolidated financial statements for this business would have been audited in accordance with PCAOB standards, or if GEODynamics had been subject to internal controls applicable to a public company under the Sarbanes-Oxley Act of 2002.
 
The ultimate impact of recent tax reform may differ from the Company’s estimates.
 
The ultimate impact of the recently enacted legislation in the United States commonly known as the Tax Cuts and Jobs Act (“Tax Reform Legislation”) may differ from the Company’s estimates, possibly materially, due to changes in the interpretations and assumptions made by the Company as well as additional regulatory and accounting guidance that may be issued and actions the Company may take as a result of the Tax Reform Legislation.
 
We may not have adequate insurance for potential liabilities and our insurance may not cover certain liabilities, including litigation risks.
 
The products that we manufacture and the services that we provide are complex, and the failure of our equipment to operate properly or to meet specifications may greatly increase our customers’ costs. In addition, many of these products are used in inherently hazardous applications where an accident or product failure can cause personal injury or loss of life, damages to property, equipment, or the environment, regulatory investigations and penalties, and the suspension or cancellation of the end-user’s operations. If our products or services fail to meet specifications, or are involved in accidents or failures, we could face warranty, contract, or other litigation claims for which we may be held responsible and our reputation for providing quality products may suffer. 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
 
Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.
 
We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure, or third-party facilities and infrastructure; and threats from terrorist acts. Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities, essential to our operations, and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
 

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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. While no customer accounted for more than 10% of our consolidated revenues in 2016 or 2015, Halliburton Company represented 16% of our consolidated revenues in 2017. The loss of a significant portion of 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 one industry impacts our overall exposure to credit risk, 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. Many of our customers finance their activities through cash flow from operations, the incurrence of debt, or the issuance of equity. Many of our customers have experienced substantial reductions in their cash flows from operations, and some are experiencing liquidity shortages, lack of access to capital and credit markets, a reduction in borrowing bases under reserve-based credit facilities, and other adverse impacts to their financial condition. These conditions may result in a significant reduction in our customers’ liquidity and ability to pay or otherwise perform 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.
 
We may assume contractual risks in developing, manufacturing and delivering products in our Offshore/Manufactured Products business segment.
 
Many of our products from our Offshore/Manufactured 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. Our actual costs, and any gross profit realized on these fixed-price contracts, may vary from the initially expected contract economics. 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. There is inherent risk in the estimation process including significant unforeseen technical and logistical challenges, or longer than expected lead times. 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.
 
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.
 
Backlog in our Offshore/Manufactured Products segment is subject to unexpected adjustments and cancellations and, therefore, has limitations as an indicator of our future revenues and earnings.
 
The revenues projected in our Offshore/Manufactured 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. 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 or deferrals 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 cancellable 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 canceled. While backlog cancellations have not been significant in the past, we incurred cancellations totaling $3.5 million, $3.7 million and $21.1 million during 2017, 2016 and 2015, respectively. If commodity prices do not continue to improve, we may incur additional cancellations or experience continued declines in our backlog. 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.

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We might be unable to employ a sufficient number of technical and service personnel.
 
Many of the products that we sell, especially in our Offshore/Manufactured 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 in each of our businesses 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. When these events occur, our cost structure increases and our growth potential could be impaired. Conversely, during periods of reduced activity, we are forced to reduce headcount, freeze or reduce wages, and implement other cost-saving measures which could lead to job abandonment by our technical and service personnel.
 
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 product and service offerings, we compete with the oil and natural 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 many 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. Many 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 products and services 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. Additionally, the development and commercialization of new products and services requires substantial capital expenditures and we may not have access to needed capital at attractive rates or at all due to our financial condition, disruptions of the bank or capital markets, or other reasons beyond our control to continue these activities. Should our technologies become the less attractive solution, our operations and profitability would be negatively impacted.
 
We may be subject to litigation if another party claims that we have infringed upon its intellectual property rights.
 
The tools, techniques, methodologies, programs, and components we use to provide our products and services may infringe, or be alleged to infringe, upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs, and may distract management from running our core business. Royalty payments under a license from third parties, if available, would increase our costs. If a license was not available, we might not be able to continue providing a particular service or product. Any of these developments could have a material adverse effect on our business, financial condition, and results of operations.
 
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 or at reasonable costs due to supply issues, import taxes or the like, 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, spills, 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

-25-



circumstances or against all risks. The occurrence of a significant event not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition.
 
We might be unable to protect our intellectual property rights.
 
We rely on a variety of intellectual property rights that we use in our Offshore/Manufactured Products and Completion Services businesses, particularly our patents relating to our FlexJoint® and Merlin™ technology and intervention and downhole extended-reach tools (including our HydroPull® tool) 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 or other tribunal 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. We are also a party to a proceeding that is currently being heard by the U.S. Supreme Court regarding whether inter partes review proceedings of intellectual property rights before an executive agency tribunal are constitutional, or whether the adjudication of patent validity must take place in Article III federal courts. 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.
 
The Spin-Off of Civeo may subject us to future liabilities.
 
We spun off (the “Spin-Off”) our accommodations business to Civeo Corporation (“Civeo”), a stand-alone, publicly traded corporation, through a tax-free distribution to our stockholders on May 30, 2014.
 
Pursuant to agreements we entered into with Civeo in connection with the Spin-Off, we and Civeo are each generally responsible for the obligations and liabilities related to our respective businesses. Pursuant to those agreements, we and Civeo each agreed to cross-indemnities principally designed to allocate financial responsibility for the obligations and liabilities of our business to us and those of Civeo’s business to it. However, third parties, including governmental agencies, could seek to hold us responsible for obligations and liabilities that Civeo agreed to retain or assume, and there can be no assurance that the indemnification from Civeo will be sufficient to protect us against the full amount of such obligations and liabilities, or that Civeo will be able to fully satisfy its indemnification obligations. Additionally, if a court were to determine that the Spin-Off or related transactions, including the payment of the dividend we received from Civeo, were consummated with the actual intent to hinder, delay or defraud current or future creditors or resulted in Civeo receiving less than reasonably equivalent value when it was insolvent, or that it was rendered insolvent, inadequately capitalized or unable to pay its debts as they become due, then it is possible that the court could disregard the allocation of obligations and liabilities agreed to between us and Civeo and impose substantial obligations and liabilities on us, void some or all of the Spin-Off transactions or require us to repay some or all of the dividend we received in connection with the Spin-Off. Any of the foregoing could adversely affect our financial condition and our results of operations.
 
In connection with the Spin-Off, we received a private letter ruling from the Internal Revenue Service (“IRS”) regarding certain aspects of the Spin-Off. The private letter ruling, and an opinion we received from our tax advisor, each rely on certain facts, assumptions, representations and undertakings from us and Civeo regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, we may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant tax liabilities. In addition, an opinion of counsel is not binding upon the IRS, so, notwithstanding the opinion of our tax advisor, the IRS could conclude upon audit that the Spin-Off is taxable in full or in part if it disagrees with the conclusions in the opinion, or for other reasons, including as a result of certain significant changes in our or Civeo’s stock ownership. If the Spin-Off is determined to be taxable for U.S. federal income tax purposes for any reason, we and/or our stockholders could incur significant income tax liabilities.
 
The issuance or sale of shares of our common stock, or rights to acquire shares of our common stock, could depress the trading price of our common stock.
 
We may offer or issue our common stock, preferred stock or other securities that are convertible into or exercisable for our common stock to finance our operations or fund acquisitions, or for other purposes. If we issue additional shares of our common stock or rights to acquire shares of our common stock, if any of our existing stockholders sells a substantial amount of our common

-26-



stock, or if the market perceives that such issuances or sales may occur, then the trading price of our common stock may significantly decrease.
 
In connection with the GEODynamics Acquisition, we issued approximately 8.66 million shares of our common stock to the entity from whom we acquired that business, and we granted that entity and certain other selling stockholders registration rights pursuant to a registration rights agreement. On January 19, 2018, we filed a Registration Statement on Form S‑3 with the SEC registering the resale of the common stock issued to such selling stockholders. We also agreed under the registration rights agreement to, among other things, (i) facilitate up to two underwritten offerings for such selling stockholders, (ii) facilitate certain block trades for such selling stockholders and (iii) provide certain piggyback registration rights to such selling stockholders. We are unable to predict the effect that actions by such selling stockholders will have on the price at which our common stock trades.
 
Item 1B. Unresolved Staff Comments
 
None.
 
Item 2. Properties
 
The Company owns or leases numerous manufacturing facilities, service centers, sales and administrative offices, storage yards and data processing centers in support of its worldwide operations. The following presents the location of the Company’s principal owned or leased facilities, by segment.
 
Offshore/Manufactured Products – Rio de Janeiro and Macae, Brazil; Aberdeen, Bathgate and West Lothian, Scotland; Barrow-in-Furness, England; Rayong, Thailand; Singapore; Navi Mumbai, India; Shenzhen, China; Abu Dhabi, UAE; and in the United States: Arlington, Houston and Lampasas, Texas; Oklahoma City and Tulsa, Oklahoma and Houma, Louisiana.
 
Well Site Services – Neuquén and Cutral Co, Argentina, Grand Prairie and Red Deer, Canada; and in the United States: Alice, Houston, and Midland, Texas; New Iberia and Houma, Louisiana; Casper and Rock Springs, Wyoming; Williston, North Dakota and Renton, Washington.
 
The principal owned or leased facilities for the GEODynamics operations acquired on January 12, 2018 are located in Millsap, Fort Worth, Weatherford, Pleasanton and Midland, Texas; Clearfield, Pennsylvania; Dickinson, North Dakota and Pinemont, Oklahoma in the United States; and Aberdeen, Scotland.
 
Our principal corporate offices are located in Houston, Texas.
 
We believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing additional suitable space upon expiration of our current lease terms.
 
Item 3. Legal Proceedings
 
Information regarding legal proceedings is set forth in Note 13, "Commitments and Contingencies," of the Consolidated Financial Statements and is incorporated herein by reference.
 
Item 4. Mine Safety Disclosures
 
Not applicable.
 

-27-



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 60,062,963 shares of common stock outstanding as of February 16, 2018. The approximate number of record holders of our common stock as of February 16, 2018 was 19. Our common stock is traded on the New York Stock Exchange (“NYSE”) under the ticker symbol OIS. The closing price of our common stock on February 16, 2018 was $27.30 per share.
 
The following table sets forth the range of high and low quarterly sales prices of our common stock as reported by the NYSE (composite transaction):
 
Price
 
High
 
Low
2018
 
 
 
First Quarter (through February 16, 2018)
$
34.72

 
$
26.65

2017
 
 
 
First Quarter
$
41.25

 
$
30.25

Second Quarter
33.75

 
25.25

Third Quarter
28.85

 
20.90

Fourth Quarter
29.15

 
20.23

2016
 
 
 
First Quarter
$
33.05

 
$
21.44

Second Quarter
36.73

 
28.46

Third Quarter
33.79

 
27.07

Fourth Quarter
41.75

 
28.00

 
We have not declared or paid any cash dividends on our common stock since our initial public offering in 2001 and our Amended Revolving Credit Facility limits 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.
 
PERFORMANCE GRAPH
 
The following graph and chart compare the cumulative five-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 PHLX Oil Service Sector index, an index of oil and gas related companies that represent an industry composite of the Company's peer group, and a customized peer group of sixteen companies, with the individual companies listed in footnote (1) below for the period from December 31, 2012 to December 31, 2017. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2012 and assume the reinvestment of all dividends. The stockholder return set forth below is not necessarily indicative of future performance. The following graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that Oil States specifically incorporates it by reference into such filing.
 
(1)
The sixteen companies included in the Company's customized peer group are: Archrock, Inc., Bristow Group Inc., Carbo Ceramics Inc., Core Laboratories N.V., Dril-Quip, Inc., Forum Energy Technologies, Inc., Franks International N.V., Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Key Energy Services, Inc., McDermott International Inc., Oceaneering International, Inc., Patterson UTI Energy, Inc., RPC, Inc., Superior Energy Services, Inc. and Tidewater Inc.
 

-28-



COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Oil States International, Inc., the S&P 500 Index,
the PHLX Oil Service Sector Index, and a Peer Group
chart-84893b980fe6169b19e.jpg
As of December 31,
 
Cumulative Total Return*
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Oil States International, Inc.
 
$
100.00

 
$
142.19

 
$
119.65

 
$
66.67

 
$
95.42

 
$
69.24

Peer Group
 
100.00

 
142.17

 
100.97

 
72.18

 
91.89

 
78.02

PHLX Oil Service Sector
 
100.00

 
130.93

 
110.66

 
85.70

 
107.87

 
92.11

S&P 500
 
100.00

 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

 
*$100 invested on December 31, 2012 in stock or index, including reinvestment of dividends. Fiscal year ended December 31.
 
Information used in the graph and table 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. Used with permission.
 
Unregistered Sales of Equity Securities and Use of Proceeds
 
None.
 
Purchases of Equity Securities by the Issuer and Affiliated Purchases
 
Period
 
Total Number of Shares Purchased(1)
 
Average Price Paid per Share(1)
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(2)
October 1 through October 31, 2017
 
143

 
$
25.35

 

 
$
120,544,560

November 1 through November 30, 2017
 

 

 

 
120,544,560

December 1 through December 31, 2017
 
323

 
25.04

 

 
120,544,560

Total
 
466

 
$
25.14

 

 
 

 
(1)
The 466 shares purchased during the three-month period ended December 31, 2017 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock.
 
(2)
On July 29, 2015, the Company’s Board of Directors approved the termination of our then existing share repurchase program and authorized a new program providing for the repurchase of up to $150 million of the Company’s common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018.

-29-



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, 2017. 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 May 2014, we completed the spin-off of our accommodations segment and, in September 2013, we sold our tubular services segment. Accordingly, all periods presented below have been reclassified to reflect the presentation of our accommodations and tubular services segments as discontinued operations.
 
Selected Financial Data
(In thousands, except per share amounts)
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
670,627

 
$
694,444

 
$
1,099,977

 
$
1,819,609

 
$
1,629,134

Costs and expenses:
 
 
 
 
 
 
 
 
 
Product and service costs
520,755

 
526,770

 
785,698

 
1,205,884

 
1,113,168

Selling, general and administrative expenses
114,816

 
124,033

 
132,664

 
169,432

 
150,967

Depreciation and amortization expense
107,667

 
118,720

 
131,257

 
124,776

 
109,231

Other operating (income) expense, net
1,261

 
(5,796
)
 
(4,648
)
 
9,262

 
8,491

 
744,499

 
763,727

 
1,044,971

 
1,509,354

 
1,381,857

Operating income (loss)
(73,872
)
 
(69,283
)
 
55,006

 
310,255

 
247,277

Interest expense
(4,674
)
 
(5,343
)
 
(6,427
)
 
(17,173
)
 
(38,830
)
Interest income
359

 
399

 
543

 
560

 
628

Loss on extinguishment of debt(1)

 

 

 
(100,380
)
 
(6,168
)
Other income
775

 
902

 
1,446

 
3,082

 
1,220

Income (loss) from continuing operations before income taxes
(77,412
)
 
(73,325
)
 
50,568

 
196,344

 
204,127

Income tax benefit (provision)(2)
(7,438
)
 
26,939

 
(22,197
)
 
(69,117
)
 
(75,068
)
Net income (loss) from continuing operations
(84,850
)
 
(46,386
)
 
28,371

 
127,227

 
129,059

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

 
(4
)
 
226

 
51,776

 
292,217

Net income (loss)
(84,850
)
 
(46,390
)
 
28,597

 
179,003

 
421,276

Less: Net income attributable to noncontrolling interest

 

 

 

 
18

Net income (loss) attributable to Oil States
$
(84,850
)
 
$
(46,390
)
 
$
28,597

 
$
179,003

 
$
421,258

 
 
 
 
 
 
 
 
 
 
Basic net income (loss) per share attributable to Oil States from:
 
 
 
 
 
 
 
 
 
Continuing operations
$
(1.69
)
 
$
(0.92
)
 
$
0.55

 
$
2.37

 
$
2.32

Discontinued operations

 

 
0.01

 
0.96

 
5.26

Net income (loss)
$
(1.69
)
 
$
(0.92
)
 
$
0.56

 
$
3.33

 
$
7.58

 
 
 
 
 
 
 
 
 
 
Diluted net income (loss) per share attributable to Oil States from:
 
 
 
 
 
 
 
 
 
Continuing operations
$
(1.69
)
 
$
(0.92
)
 
$
0.55

 
$
2.35

 
$
2.31

Discontinued operations

 

 
0.01

 
0.96

 
5.22

Net income (loss)
$
(1.69
)
 
$
(0.92
)
 
$
0.56

 
$
3.31

 
$
7.53

 
 
 
 
 
 
 
 
 
 
Weighted average number of common shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
50,139

 
50,174

 
50,269

 
52,862

 
54,969

Diluted
50,139

 
50,174

 
50,335

 
53,151

 
55,327


-30-



 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Other Data:
 
 
 
 
 
 
 
 
 
Net cash provided by continuing operating activities
$
95,382

 
$
149,257

 
$
255,768

 
$
302,644

 
$
235,086

Net cash (used in) provided by continuing investing activities, including capital expenditures
(47,615
)
 
(29,292
)
 
(147,196
)
 
(198,504
)
 
393,509

Net cash used in continuing financing activities
(65,060
)
 
(84,875
)
 
(124,722
)
 
(378,912
)
 
(299,928
)
EBITDA, as defined(3)
34,570

 
50,339

 
187,709

 
438,113

 
357,710

Capital expenditures
35,171

 
29,689

 
114,738

 
199,256

 
164,895

Acquisitions of businesses, net of cash acquired
12,859

 

 
33,427

 
157

 
44,260

Cash used for treasury stock purchases
16,283

 

 
105,916

 
226,303

 
108,535

 
As of December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
53,459

 
$
68,800

 
$
35,973

 
$
53,263

 
$
599,306

Total current assets
455,937

 
489,977

 
611,473

 
826,666

 
1,525,907

Property, plant and equipment, net
498,890

 
553,402

 
638,725

 
649,846

 
1,902,789

Total assets
1,301,511

 
1,383,898

 
1,596,471

 
1,806,167

 
4,109,863

Long-term debt and capital leases, excluding current portion
4,870

 
45,388

 
125,887

 
143,390

 
951,294

Total stockholders' equity
1,132,713

 
1,204,307

 
1,255,672

 
1,340,657

 
2,625,294

 
We believe that net income (loss) 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 (loss) attributable to continuing operations, as derived from our financial information (in thousands):
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
Net income (loss) attributable to Oil States - continuing operations
$
(84,850
)
 
$
(46,386
)
 
$
28,371

 
$
127,227

 
$
129,041

Depreciation and amortization expense
107,667

 
118,720

 
131,257

 
124,776

 
109,231

Interest expense, net
4,315

 
4,944

 
5,884

 
16,613

 
38,202

Loss on extinguishment of debt(1)

 

 

 
100,380

 
6,168

Income tax provision (benefit)(2)
7,438

 
(26,939
)
 
22,197

 
69,117

 
75,068

EBITDA, as defined(3)
$
34,570

 
$
50,339

 
$
187,709

 
$
438,113

 
$
357,710

____________________
(1)
During 2014, we recognized losses on the extinguishment of debt totaling $100.4 million primarily due to the repurchase of our remaining 6 1/2% Notes and 5 1/8% Notes. During 2013, we recognized a loss on the extinguishment of debt totaling $6.2 million in connection with the repurchase of a portion of our 5 1/8% Notes.
 
(2)
During the fourth quarter of 2017, we recorded a non-cash charge of $28.2 million associated with U.S. income tax legislation enacted on December 22, 2017. See Note 12, "Income Taxes."
 
(3)
The term EBITDA as defined consists of net income (loss) attributable to continuing operations plus interest expense, net, loss on extinguishment of debt, income tax provision (benefit), 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 (loss) 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. We have included EBITDA as defined as a supplemental disclosure because our management believes that EBITDA as defined provides useful information regarding our ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing our operating performance with the performance of other companies that have different financing and capital structures or tax rates. We use EBITDA as defined to compare and to monitor the performance of our business segments to other comparable public companies and as a benchmark for the award of incentive compensation under our annual incentive compensation plan.
 

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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 Offshore/Manufactured Products and Well Site Services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to invest capital in the exploration for and development of crude oil and natural gas reserves. Our customers’ capital spending programs are generally based on their cash flows and 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 future expectations with respect to crude oil and natural gas prices.
 
Our consolidated results of operations reflect current industry trends and customer spending activities which are focused on growth in the U.S. shale play regions with weaker U.S. Gulf of Mexico and international activity. In addition, investments in deepwater markets globally have slowed significantly since the start of this prolonged industry downturn in 2014.
 
A severe industry downturn started in the second half of 2014 and continued in 2017, driven by global economic uncertainties and high levels of global oil production. As shown in the table that follows, significant downward crude oil price volatility began in late 2014 with Intercontinental Exchange Brent (“Brent”) crude oil declining from an average of $110 per barrel in the second quarter of 2014 to an average of $34 per barrel in the first quarter of 2016 (a level last seen in 2004). The sustained material decrease in crude oil prices relative to 2014 was primarily attributable to high levels of global crude oil inventories resulting from significant production growth in the U.S. shale plays, the strengthening of the U.S. dollar relative to other currencies, and increased production by OPEC. OPEC demonstrated, throughout 2015 and through November of 2016 an unwillingness to modify production levels, as it had done in previous years, in an effort to protect its market share. These production increases were partially offset by growth in global crude oil demand. The combination of these and other factors caused a global supply and demand imbalance for crude oil which resulted in materially lower crude oil prices. Non-OPEC production, particularly in the United States, began to decline in 2015 due to substantially reduced investment in drilling and completion activity triggered by lower crude oil prices leading to some recovery in crude oil prices in 2016 and 2017 relative to the crude oil price lows experienced in early 2016. In late 2016, OPEC agreed to production cuts (subsequently extended through December 2018) which should, over time, if the cuts are adhered to, result in further reductions in global crude oil inventories and a more favorable commodity price environment.
 
Brent crude oil prices averaged $54 per barrel in 2017, which was 24% above the 2016 average of $44 per barrel, but is 45% below the average in 2014. Similarly, the average price of West Texas Intermediate (“WTI”) was $51 per barrel in 2017, up 17% from the 2016 average of $43 per barrel, but was 45% below the average in 2014. The year-over-year improvement in crude oil prices was driven by the belief that OPEC and Russia, its key ally in the effort to stabilize the global crude oil market, would be successful in cutting their production. However, improvements in crude oil prices rapidly translated into increased drilling activity in U.S. shale play developments in areas such as the Permian Basin in 2017, which is leading to higher domestic production. Spending in these regions, which began to improve in the second half of 2016 in response to higher crude oil prices, has positively influenced the overall drilling and completion activity in these regions and, therefore, the activity of our Well Site Services segment as well as for short-cycle products within our Offshore/Manufactured Products segment in 2017. Expectations with respect to the longer-term price for Brent crude oil will continue to influence our customers’ spending related to global offshore drilling and development and, thus, a significant portion of the activity of our Offshore/Manufactured Products segment.
 
Given the historical volatility of crude oil prices, there remains a degree of risk that prices could remain at their current levels or deteriorate further due to increases in global inventory levels, increasing domestic crude oil production, slowing growth rates in various global regions, use of alternatives, a more sustained movement to electric vehicles and/or the potential for ongoing supply/demand imbalances. Conversely, if the global supply of crude oil were to decrease due to a prolonged reduction in capital investment by our customers or if government instability in a major oil-producing nation develops, and energy demand were to continue to increase in the United States, India and China, a sustained recovery in WTI and Brent crude oil prices could occur. In any event, continued crude oil price improvements will depend upon the balance of global supply and demand, with a corresponding continued

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reduction in global inventories, the timing of which is difficult to predict. If commodity prices do not continue to improve, or decline, demand for our products and services could continue to be weak or could decline further.

Natural gas prices improved slightly over the past year from an average of $2.52 per mmBtu in 2016 to an average of $2.99 per mmBtu during 2017. Customer spending in the natural gas shale plays has been limited due to associated natural gas being produced from unconventional oil wells in North America. If natural gas production growth surpasses demand growth in the United States, and/or if the supply of natural gas were to increase, whether from conventional or unconventional production or associated natural gas production from oil wells, prices for natural gas could remain depressed for an extended period of time and could result in fewer rigs drilling for natural gas.
 
Recent WTI crude oil, Brent crude oil and natural gas pricing trends are as follows:
 
 
Average price(1) for quarter ended
 
Average price(1) for year ended December 31
Year
 
March 31
 
June 30
 
September 30
 
December 31
 
WTI Crude (per bbl)
 
 
 
 
 
 
 
 
2017
 
$
51.62

 
$
48.14

 
$
48.18

 
$
55.27

 
$
50.80

2016
 
33.35

 
45.46

 
44.85

 
49.14

 
43.29

2015
 
48.49

 
57.85

 
46.49

 
41.94

 
48.66

2014
 
98.68

 
103.35

 
97.87

 
73.21

 
93.17

Brent Crude (per bbl)
 
 
 
 
 
 
 
 
2017
 
$
53.59

 
$
49.59

 
$
52.10

 
$
61.40

 
$
54.12

2016
 
33.84

 
45.57

 
45.80

 
49.11

 
43.67

2015
 
53.98

 
61.65

 
50.44

 
43.56

 
52.32

2014
 
108.14

 
109.69

 
101.90

 
76.43

 
98.97

Henry Hub Natural Gas
(per mmBtu)
 
 
 
 
 
 
2017
 
$
3.02

 
$
3.08

 
$
2.95

 
$
2.90

 
$
2.99

2016
 
1.99

 
2.15

 
2.88

 
3.04

 
2.52

2015
 
2.90

 
2.75

 
2.76

 
2.12

 
2.62

2014
 
5.18

 
4.61

 
3.96

 
3.78

 
4.37

 
(1)
Source: U.S. Energy Information Administration. As of February 12, 2018, WTI crude oil, Brent crude oil and natural gas traded at approximately $59.41 per barrel, $62.20 per barrel and $2.60 per mmBtu, respectively.
 
Overview
 
Our Offshore/Manufactured Products segment provides technology-driven, highly-engineered products and services for offshore oil and natural gas production systems and facilities, as well as certain products and services to the offshore and land-based drilling and completion markets. Approximately 60% of Offshore/Manufactured Products sales in 2015 and 2016 were driven by our customers’ capital spending for offshore production systems and subsea pipelines, repairs and, to a lesser extent, upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels (referred to herein as "project-driven product revenue"). As a result, this segment is particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for crude oil and natural gas prices. Deepwater oil and gas development projects typically involve significant capital investments and multi-year development plans. Such projects are generally undertaken by larger exploration, field development and production companies (primarily international oil companies (“IOCs”) and state-run national oil companies (“NOCs”) using relatively conservative crude oil and natural gas pricing assumptions. Given the longer lead times associated with field development, we believe some of these deepwater projects, once approved for development, are less susceptible to short-term fluctuations in the price of crude oil and natural gas. However, the decline in crude oil prices that began in 2014 and continued into 2017, coupled with the relatively uncertain outlook around shorter-term and possibly longer-term pricing improvements, have caused exploration and production companies to reevaluate their future capital expenditures in regards to these deepwater projects since they are expensive to drill and complete, have long lead times to first production and may be considered uneconomical relative to the risk involved. A few development projects were sanctioned in 2017 due to re-engineering of the projects and lower development costs, which led to an improvement in final investment decisions (“FIDs”) on these projects from the previous two years. Our bookings have declined, leading to substantially reduced backlog in 2017 relative to recent years. As a result, this segment’s project-driven revenue declined $169.4 million, or 57%, from 2016 and accounted for only 33% of the segment’s total revenue in 2017. Shorter-cycle manufactured products, sold primarily to the land-based completions market, are impacted by near-term fluctuations in commodity prices. For the year ended December 31, 2017, sales of these shorter-cycle products

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(such as valves and elastomer products) for this segment increased 67% over the level reported last year due to the significant increase in U.S. land-based drilling and completion activity and represented 39% of the segment's total revenues in 2017. Revenues generated from sales of other products and services in 2017 decreased 13% from 2016 due primarily to reduced levels of service activity and represented 28% of the segment's total revenues in 2017.
 
Our Offshore/Manufactured Products segment revenues and operating income declined at a slower pace during 2015 and 2016 than our Well Site Services segment given the high levels of backlog that existed at the beginning of 2015. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued after 2014, albeit at a much slower pace. Reflecting the impact of customer (both IOCs and NOCs) delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $599 million at June 30, 2014 to $168 million at December 31, 2017, which is the lowest level reported since January 2006. The following table sets forth backlog for our Offshore/Manufactured Products segment as of the dates indicated (in millions).
 
 
Backlog as of
Year
 
March 31
 
June 30
 
September 30
 
December 31
2017
 
$
204

 
$
202

 
$
198

 
$
168

2016
 
306

 
268

 
203

 
199

2015
 
474

 
409

 
394

 
340

2014
 
578

 
599

 
543

 
490

 
Our Well Site Services segment provides completion services and, to a lesser extent, land drilling services in the United States (including the Gulf of Mexico), Canada and the rest of the world. U.S. drilling and completion activity and, in turn, our Well Site Services results, are particularly sensitive to near-term fluctuations in commodity prices given the call-out nature of our operations in the segment. While there has been notable improvement in 2017, Well Site Services continues to be significantly negatively affected by the material decline in crude oil prices since 2014.
 
Within this segment, our Completion Services business supplies equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the Completion Services business is dependent primarily upon the level and complexity of drilling, completion, and workover activity throughout North America. Well complexity has increased with the continuing transition to multi-well pads and the drilling of longer lateral wells along with the increased number of frac stages completed in horizontal wells. Similarly, demand for our Drilling Services operations is driven by activity in our primary land drilling markets of the Permian Basin in West Texas, where we drill oil wells, and the U.S. Rocky Mountain area, where we drill both liquids-rich and natural gas wells.
 
Demand for our land drilling and completion services businesses is correlated to changes in the drilling rig count in North America, as well as changes in the total number of wells drilled, total footage drilled, and the number of drilled wells that are completed. The following table sets forth a summary of the average North American drilling rig count, as measured by Baker Hughes, for the periods indicated.
 
As of February 16, 2018
 
Average Rig Count for Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
U.S. Land – Oil
782

 
684

 
390

 
723

 
1,486

 
1,334

U.S. Land – Natural gas and other
174

 
169

 
97

 
219

 
319

 
371

U.S. Offshore
19

 
23

 
25

 
35

 
57

 
56

Total U.S.
975

 
876

 
512

 
977

 
1,862

 
1,761

Canada
318

 
206

 
129

 
193

 
380

 
355

Total North America
1,293

 
1,082

 
641

 
1,170

 
2,242

 
2,116

 
The average North American rig count in 2017 increased 441 rigs, or 69%, from the level reported in 2016, in response to the increase in crude oil prices discussed above.
 
Over recent years, our industry experienced increased customer spending in crude oil and liquids-rich exploration and development in the North American shale plays utilizing horizontal drilling and completion techniques. According to rig count data published by Baker Hughes, the U.S. oil rig count peaked in October 2014 at 1,609 rigs but has declined materially since late 2014 due to much lower crude oil prices, totaling 747 rigs as of December 31, 2017 (with the U.S. oil rig count having troughed at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of December 31, 2017, oil-

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directed drilling accounted for 80% of the total U.S. rig count with the balance natural gas related. The U.S. natural gas-related working rig count declined from approximately 810 rigs at the beginning of 2012 to 81 rigs in August of 2016, a more than 29 year low. Total U.S. rig count has increased 525 rigs, or 130%, since troughing in May of 2016, largely due to improved crude oil prices, decreased service costs and improved technologies applied in the shale play regions of the United States.
 
Exacerbating the steep declines in drilling activity experienced in 2015 and 2016, many of our exploration and production customers deferred well completions. These deferred completions are referred to in the industry as drilled but uncompleted wells (or “DUCs”). Given our Well Site Services segment’s exposure to the level of completion activity, an increase in the number of DUCs will have a short-term negative impact on our results of operations relative to the rig count trends but over the longer-term should have a positive impact on the segment’s results as the wells are completed.
 
Reduced demand for our products and services, coupled with a reduction in the prices we charge our customers for our services has adversely affected our results of operations, cash flows and financial position since the second half of 2014. If the current pricing environment for crude oil and natural gas does not improve, or declines further, our customers may be required to further reduce their capital expenditures, causing additional declines in the demand for, and prices of, our products and services, which would adversely affect our results of operations, cash flows and financial position. Our customers have experienced a significant decline in their revenues and cash flows relative to the commodity price declines in 2015, 2016 and into 2017, with many experiencing a significant reduction in liquidity. Several exploration and production companies declared bankruptcy during 2015 and 2016, or had to exchange equity for the forgiveness of debt, and others were forced to sell assets in an effort to preserve liquidity. However, over the past twelve months, access to capital and debt markets have improved for certain of these customers.
 
Other factors that can affect our business and financial results include but are not limited to the general global economic environment, competitive pricing pressures, regulatory changes and changes in tax laws in the United States and international markets.
 
We continue to monitor the global economy, the prices of and demand for crude oil and natural gas, and the resultant impact on the capital spending plans and operations of our customers in order to plan and manage our business.
 
Recent Developments
 
In addition to capital spending, we have invested in acquisitions of businesses complementary to our growth strategy. Our acquisition strategy has allowed us to leverage our existing and acquired products and services into new geographic locations and has expanded the breadth of our technology and product offerings. We have made strategic and complementary acquisitions in each of our business segments in recent years.
 
During 2017, we acquired, as part of our Offshore/Manufactured Products segment, complementary intellectual property and assets to expand our global crane manufacturing and service operations as well as our riser testing, inspection and repair service offerings.
 
In addition, on December 12, 2017 we entered into an agreement to acquire GEODynamics, which provides oil and gas perforation systems and downhole tools in support of completion, intervention, wireline and well abandonment operations. The GEODynamics operations will be reported as a separate business segment beginning in the first quarter of 2018 under the name “Downhole Technologies.”
 
On January 12, 2018, we closed the GEODynamics Acquisition for a purchase price consisting of (i) $295 million in cash (net of cash acquired), which we funded through borrowings under our Revolving Credit Facility, (ii) approximately 8.66 million shares of our common stock (having a market value of approximately $295 million as of the closing date) and (iii) an unsecured $25 million promissory note that bears interest at 2.5% per annum and matures on July 12, 2019. For the years ended December 31, 2017 and 2016, GEODynamics generated $166.4 million and $72.1 million of revenues, respectively, and $24.4 million and $0.1 million of net income, respectively.
 
Following the close of the GEODynamics Acquisition, we completed several financing transactions to extend the maturity of our debt while providing us with the flexibility to repay outstanding borrowings under our revolving credit facility with anticipated future cash flows from operations.
 
On January 30, 2018, we sold $200.0 million aggregate principal amount of our 1.50% convertible senior notes due 2023 through a private placement to qualified institutional buyers. We received net proceeds from the offering of the Notes of approximately $194.0 million, after deducting fees and estimated expenses. We used the net proceeds from the sale of the Notes to repay a portion

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of the borrowings outstanding under our Revolving Credit Facility, substantially all of which were drawn to fund the cash portion of the purchase price of the GEODynamics Acquisition.
 
Concurrently with the Notes offering, we amended our Revolving Credit Facility by entering into the Amended Revolving Credit Facility, to extend the maturity date of the facility to January 2022, permit the issuance of the Notes and provide for up to $350.0 million in borrowing capacity.
 
See Note 18, “Subsequent Events,” to the Consolidated Financial Statements included in this Annual Report on Form 10-K for further discussion of these recent developments.
 

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Consolidated Results of Operations
 
Prior to the acquisition of GEODynamics, we managed and measured our business performance in two distinct operating segments: Well Site Services and Offshore/Manufactured Products. Selected financial information by business segment for years ended December 31, 2017, 2016 and 2015 is summarized as follows (dollars in thousands):
 
Year Ended December 31,
 
 
 
 
 
Variance 2017 vs. 2016
 
 
 
Variance 2016 vs. 2015
 
2017
 
2016
 
$
 
%
 
2015
 
$
 
%
Revenues
 
 
 
 
 
 
 

 
 
 
 
 
 

Well Site Services -
 
 
 
 
 
 
 

 
 
 
 
 
 

Completion Services
$
234,252

 
$
163,060

 
$
71,192

 
44
 %
 
$
308,077

 
$
(145,017
)
 
(47
)%
Drilling Services
54,462

 
22,594

 
31,868

 
141
 %
 
67,782

 
(45,188
)
 
(67
)%
Total Well Site Services
288,714

 
185,654

 
103,060

 
56
 %
 
375,859

 
(190,205
)
 
(51
)%
Offshore/Manufactured Products -
 
 
 
 
 
 
 
 
 
 
 
 
 
Project-driven products
126,960

 
296,368

 
(169,408
)
 
(57
)%
 
433,056

 
(136,688
)
 
(32
)%
Short-cycle products
147,463

 
88,291

 
59,172

 
67
 %
 
100,355

 
(12,064
)
 
(12
)%
Other products and services
107,490

 
124,131

 
(16,641
)
 
(13
)%
 
190,707

 
(66,576
)
 
(35
)%
Total Offshore/Manufactured Products
381,913

 
508,790

 
(126,877
)
 
(25
)%
 
724,118

 
(215,328
)
 
(30
)%
Total
$
670,627

 
$
694,444

 
$
(23,817
)
 
(3
)%
 
$
1,099,977

 
$
(405,533
)
 
(37
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Product and service costs
 
 
 
 
 
 
 
 
 
 
 
 
 
Well Site Services -
 
 
 
 
 
 
 
 
 
 
 
 
 
Completion Services
$
200,514

 
$
153,356

 
$
47,158

 
31
 %
 
$
237,441

 
$
(84,085
)
 
(35
)%
Drilling Services
47,999

 
21,797

 
26,202

 
120
 %
 
56,274

 
(34,477
)
 
(61
)%
Total Well Site Services
248,513

 
175,153

 
73,360

 
42
 %
 
293,715

 
(118,562
)
 
(40
)%
Offshore/Manufactured Products
272,243

 
351,617

 
(79,374
)
 
(23
)%
 
491,983

 
(140,366
)
 
(29
)%
Total
$
520,756

 
$
526,770

 
$
(6,014
)
 
(1
)%
 
$
785,698

 
$
(258,928
)
 
(33
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross profit(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
Well Site Services -
 
 
 
 
 
 
 
 
 
 
 
 
 
Completion Services
$
33,739

 
$
9,704

 
$
24,035

 
248
 %
 
$
70,636

 
$
(60,932
)
 
(86
)%
Drilling Services
6,462

 
797

 
5,665

 
711
 %
 
11,508

 
(10,711
)
 
(93
)%
Total Well Site Services
40,201

 
10,501

 
29,700

 
283
 %
 
82,144

 
(71,643
)
 
(87
)%
Offshore/Manufactured Products
109,671

 
157,173

 
(47,502
)
 
(30
)%
 
232,135

 
(74,962
)
 
(32
)%
Total
$
149,872

 
$
167,674

 
$
(17,802
)
 
(11
)%
 
$
314,279

 
$
(146,605
)
 
(47
)%
Gross profit as a percentage of revenues(1)
 
 
 
 
 
 
 
 
 
 
Well Site Services -
 

 
 

 
 
 
 
 
 

 
 
 
 
Completion Services
14
%
 
6
%
 
 
 
 
 
23
%
 
 
 
 
Drilling Services
12
%
 
4
%
 
 
 
 
 
17
%
 
 
 
 
Total Well Site Services
14
%
 
6
%
 
 
 
 
 
22
%
 
 
 
 
Offshore/Manufactured Products
29
%
 
31
%
 
 
 
 
 
32
%
 
 
 
 
Total
22
%
 
24
%
 
 
 
 
 
29
%
 
 
 
 
 
(1)
Gross profit is computed by deducting product and service costs from revenues, and excludes depreciation expense. Gross profit as a percentage of revenues is also referred to herein as gross margin.
 

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YEAR ENDED DECEMBER 31, 2017 COMPARED TO YEAR ENDED DECEMBER 31, 2016
 
Net loss for the year ended December 31, 2017 was $84.9 million, or $(1.69) per diluted share, which included $3.4 million ($2.4 million after-tax, or $0.05 per diluted share) of severance, downsizing and other charges and $29.2 million ($0.58 per diluted share) of additional non-cash income tax expense related to U.S. tax law changes and a decision to carryback net operating losses incurred in 2016 against taxable income reported in 2014. Excluding these charges, the 2017 net loss would have been $53.3 million, or $(1.06) per diluted share. These results compare to a net loss of $46.4 million, or $(0.92) per diluted share, reported for the year ended December 31, 2016. Results for 2016 included $5.2 million ($3.3 million after-tax, or $0.06 per diluted share) of severance and other downsizing charges. Excluding the charges, net loss would have been $43.1 million, or $(0.86) per diluted share.
 
Our consolidated results of operations also reflect current industry trends and customer spending activities which are focused on growth in the U.S. shale play regions with weaker U.S. Gulf of Mexico and international activity. In addition, investments in deepwater markets globally have slowed significantly since the start of the recent industry downturn in 2014.
 
Revenues. Consolidated revenues decreased $23.8 million, or 3%, in 2017 compared to 2016 due to declines in our Offshore/Manufactured Products segment, substantially offset by improvements in our Well Site Services segment. During 2017, over 50% of consolidated revenues were driven by U.S. shale play activity.
 
Our Well Site Services segment revenues increased $103.1 million, or 56%, in 2017 compared to 2016 due to growth of both Completion Services and Drilling Services revenues. Our Completion Services revenues increased $71.2 million, or 44%, in 2017 compared to 2016, with the impact of a higher commodity price environment and lower service costs driving increased U.S. land-based activity, partially offset by the timing of customer activity in certain international markets. The number of Completion Services job tickets in 2017 increased 26% over the prior-year and revenue per Completion Services job increased 13% year-over-year as a result of higher completions activity, increased well completion complexity, a more favorable job mix and improved pricing. Our Drilling Services revenues increased $31.9 million, or 141%, to $54.5 million in 2017 from 2016 due to higher utilization of our land drilling rigs, which increased from an average of 12% during 2016 to an average of 29% in 2017, and increased dayrates.
 
Our Offshore/Manufactured Products segment revenues decreased $126.9 million, or 25%, in 2017 compared to 2016 primarily as a result of a decline in demand for deepwater project-driven products (primarily subsea pipeline infrastructure, offshore production and drilling products), lower levels of service activities and a backlog position that has trended significantly lower since mid-2014. These deepwater project-driven revenue declines were partially offset by a 67% increase in sales of our short-cycle products. Shorter-cycle products, such as elastomers and valves, have benefited from increased land-based drilling and completion activity in the United States. Bidding and quoting activity, along with orders from customers, for our Offshore/Manufactured Products segment continued, albeit at a much slower pace. Reflecting the impact of customer delays and deferrals in approving major, capital intensive projects in light of the prolonged low commodity price environment, backlog in our Offshore/Manufactured Products segment decreased from $199 million at December 31, 2016 to $168 million at December 31, 2017.
 
Cost of Sales and Services. Our consolidated cost of sales and services decreased $6.0 million, or 1%, in 2017 compared to 2016 as a result of decreased cost of sales and services at our Offshore/Manufactured Products segment of $79.4 million or 23%, which was partially offset by a $73.4 million, or 42%, increase in cost of services at our Well Site Services segment. Consolidated gross profit as a percentage of revenues decreased from 24% in 2016 to 22% in 2017 with gross margin expansion within our Well Site Services segment offset by the impact of a significant reduction in sales of project-driven products in our Offshore/Manufactured Products segment.
 
Our Well Site Services segment cost of services increased $73.4 million, or 42%, in 2017 compared to 2016 as a result of a $47.2 million, or 31%, increase in Completion Services cost of services and a $26.2 million, or 120%, increase in service costs in our Drilling Services business. These increases in cost of services, which are strongly correlated to the revenue increases in these businesses, reflect the increase in land-based activity in the United States. Costs increases included higher personnel costs from increased employee overtime and costs associated with headcount additions made during 2017. Our Well Site Services segment gross profit as a percentage of revenues increased from 6% in 2016 to 14% in 2017. Our Completion Services gross profit as a percentage of revenues increased from 6% in 2016 to 14% in 2017 primarily due to the increase in service revenues. Our Drilling Services gross profit as a percentage of revenues improved from 4% in 2016 to 12% in 2017 primarily due to increased rig utilization and cost absorption.
 
Our Offshore/Manufactured Products segment cost of sales decreased $79.4 million, or 23%, in 2017 compared to 2016 reflecting the decrease in project-driven revenues. Gross profit as a percentage of revenues decreased from 31% in 2016 to 29% in 2017, due primarily to the reported 57% decline in sales of project-driven products, which was partially offset by a 67% increase in sales of short-cycle products.

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Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $9.2 million, or 7%, in 2017 from the prior-year primarily due to the impact of cost reduction initiatives and lower employee severance-related charges in 2017, partially offset by higher incentive compensation accruals.
 
Depreciation and Amortization. Depreciation and amortization expense decreased $11.1 million, or 9%, in 2017 compared to 2016 primarily due to certain assets becoming fully depreciated coupled with overall lower levels of capital expenditures.
 
Other Operating (Income) Expense, Net. Other operating (income) expense, net moved from other operating income of $5.8 million in 2016 to other operating expense of $1.3 million in 2017, reflecting primarily the impact of foreign currency exchange gains or losses recognized in the respective periods.
 
Operating Loss. Our consolidated operating loss increased from $69.3 million in 2016 to $73.9 million in 2017 primarily as a result of a decrease in operating income from our Offshore/Manufactured Products segment of $48.9 million due to a continued decline in offshore-related activity, substantially offset by an improvement of $48.8 million in the operating losses from our Well Site Services segment. Corporate expenses were $52.9 million in 2017, an increase of $4.5 million from the prior-year due primarily to higher incentive compensation accruals, increased stock-based compensation expense and acquisition related expenses incurred in 2017.
 
Interest Expense and Interest Income. Net interest expense decreased $0.6 million, or 13%, in 2017 compared to 2016 primarily due to a reduction in average amounts outstanding under the Revolving Credit Facility partially offset by higher unused commitment fees paid to our lenders. Interest expense as a percentage of total debt outstanding increased from 6.5% in 2016 to 17.3% in 2017 due to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under the Revolving Credit Facility and non-cash amortization of debt issuance costs.
 
Income Tax Expense. Our income tax provision for 2017 was $7.4 million (an income tax benefit of $21.8 million, or 28.1% of pre-tax losses, after excluding the discrete charges discussed below) compared to an income tax benefit of $26.9 million, or 36.7% of pre-tax losses for 2016. The lower effective tax rate benefit in 2017 after excluding discrete charges was attributable to a shift in the mix between domestic pre-tax losses and foreign pre-tax income compared to the prior-year period and additional valuation allowances provided against net operating losses in certain domestic and foreign jurisdictions.
 
On December 22, 2017, the United States enacted Tax Reform Legislation which resulted in significant changes to U.S. tax and related law, including certain key federal income tax provisions applicable to multinational companies such as ours. As a result of the tax law changes, we recorded $28.2 million of incremental non-cash income tax expense related to the U.S. transition tax on our unremitted foreign subsidiary earnings and to provide valuation allowances against our foreign tax credit carryforwards (which were recorded as assets prior to U.S. tax reform). Additionally, we re-measured our other U.S. deferred tax assets and liabilities to reflect the lower U.S. corporate income tax rate which has been reduced from 35% to 21%. The Company also recorded a discrete tax charge of $1.0 million during the third quarter of 2017 related to the decision to carryback 2016 U.S. net operating losses against 2014 taxable income.
 
On a longer term basis, certain aspects of the Tax Reform Legislation are expected to have a positive impact on our future U.S. income tax expense, including the reduction in the U.S. corporate income tax rate.
 
Other Comprehensive Income (Loss). Other comprehensive income was $11.8 million in 2017 compared to a loss of $19.6 million in 2016 due to fluctuations in foreign currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For 2017 and 2016, currency translation adjustments recognized as a component of other comprehensive income (loss) were primarily attributable to the United Kingdom and Brazil. During 2017, exchange rates for the British pound strengthened compared to the U.S. dollar, while the Brazilian real weakened compared to the U.S. dollar. This compares to 2016, when exchange rates for the British pound weakened compared to the U.S. dollar, while the Brazilian real strengthened compared to the U.S. dollar. The British pound was impacted by the United Kingdom’s vote to exit the European Union in late June 2016.
 

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YEAR ENDED DECEMBER 31, 2016 COMPARED TO YEAR ENDED DECEMBER 31, 2015
 
Net loss from continuing operations for the year end December 31, 2016 was $46.4 million, or $(0.92) per diluted share, which included $5.2 million ($3.3 million after-tax, or $0.06 per diluted share) of severance and other downsizing charges. Excluding these charges, the net loss from continuing operations in 2016 would have been $43.1 million, or $(0.86) per diluted share. These results compare to net income from continuing operations of $28.4 million, or $0.55 per diluted share, reported for the year ended December 31, 2015. Results for 2015 included $6.4 million ($4.6 million after-tax, or $0.09 per diluted share) of severance and other downsizing charges, a $3.4 million ($2.4 million after-tax, or $0.05 per diluted share) provision for leasehold restoration and a higher effective tax rate driven primarily by a $4.1 million ($0.08 per diluted share) valuation allowance recorded against certain of our tax loss carry forwards in various international jurisdictions and $3.6 million ($0.07 per diluted share) in tax adjustments for certain prior period non-deductible items. Excluding the charges and the effect of the higher effective tax rate in 2015, net income from continuing operations would have been $43.1 million, or $0.84 per diluted share.
 
Revenues. Consolidated revenues decreased $405.5 million, or 37%, in 2016 compared to 2015.
 
Our Well Site Services segment revenues decreased $190.2 million, or 51%, in 2016 compared to 2015 due to decreases in both Completion Services and Drilling Services revenues. Our Completion Services revenues decreased $145.0 million, or 47%, in 2016 compared to 2015, primarily due to a 55% decrease in the number of service tickets completed as a result of continued extreme competitive pressures and depressed activity levels in the U.S. shale basins. Our Drilling Services revenues decreased $45.2 million, or 67%, in 2016 compared to 2015, primarily as a result of the significant reduction in utilization of our drilling rigs from an average of 33% during 2015 to an average of 12% in 2016 due primarily to the continued weak commodity price environment.
 
Our Offshore/Manufactured Products segment revenues decreased $215.3 million, or 30%, in 2016 compared to 2015 primarily as a result of lower contributions across most of the segment’s product lines, driven by a decline in demand for drilling products, production-related products and service activities as well as a backlog position that has trended lower since mid-2014. These revenue declines were partially offset by modest full-year increases in sales of subsea pipeline and shorter-cycle product revenues. Shorter-cycle products, such as elastomers, have benefited from increased land-based drilling and completion activity in the second half of 2016 in the United States. Backlog for the segment decreased to $199 million at December 31, 2016, from $340 million at December 31, 2015 and $490 million at December 31, 2014, due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment.
 
Cost of Sales and Services. Our consolidated cost of sales and services decreased $258.9 million, or 33%, in 2016 compared to 2015 as a result of decreased cost of sales and services at our Well Site Services and Offshore/Manufactured Products segments of $118.6 million, or 40%, and $140.3 million, or 29%, respectively. With cost of sales and services decreasing at a slower rate than our revenues, consolidated gross profit as a percentage of revenues decreased from 29% in 2015 to 24% in the 2016 due primarily to significantly lower margins realized in our Well Site Services segment in 2016.
 
Our Well Site Services segment cost of services decreased $118.6 million, or 40%, in 2016 compared to 2015 as a result of a $84.1 million, or 35%, decrease in Completion Services cost of services and a $34.5 million, or 61%, decrease in Drilling Services cost of services. These decreases in cost of services, which are strongly correlated to the revenue decreases in these businesses, reflect a reduction in variable costs along with cost reduction measures implemented in response to the material decrease in revenues caused by industry activity declines. Our Well Site Services segment gross profit as a percentage of revenues decreased from 22% in 2015 to 6% in 2016. Our Completion Services gross profit as a percentage of revenues decreased from 23% in 2015 to 6% in 2016 primarily due to the significant decline in activity and competitive industry pricing pressures. Our Drilling Services gross profit as a percentage of revenues decreased from 17% in 2015 to 4% in of 2016 primarily due to decreased rig utilization and cost absorption.
 
Our Offshore/Manufactured Products segment cost of sales decreased $140.3 million, or 29%, in 2016 compared to 2015 in correlation with the decrease in revenues. Gross profit as a percentage of revenues remained generally constant (31% in 2016 compared to 32% in 2015).
 
Selling, General and Administrative Expenses. Selling, general and administrative expenses decreased $8.6 million, or 7%, in 2016 compared to 2015 with the impact of reduced sales commissions, travel and entertainment expenses and compensation costs partially offset by higher provision for bad debt and professional fees.
 
Depreciation and Amortization. Depreciation and amortization expense decreased $12.5 million, or 10%, in 2016 compared to 2015 primarily due to certain assets becoming fully depreciated since December 31, 2015 that, due to the downturn, have not been replaced and lower levels of capital expenditures.
 

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Other Operating Income. Other operating income increased $1.1 million, to $5.8 million, in 2016 compared to 2015 primarily due to increases in foreign currency exchange rate gains.
 
Operating Income (Loss). Consolidated operating income (loss) moved from operating income of $55.0 million in 2015 to an operating loss of $69.3 million in 2016, driven by the impact of significant revenue declines due to lower industry activity and competitive industry pricing pressures. Well Site Services operating loss increased $63.7 million to $107.9 million in 2016 while Offshore/Manufactured Products operating income declined $59.3 million to $87.1 million in 2016. Corporate expenses were $48.5 million in 2016, compared to $47.2 million in 2015.
 
Interest Expense and Interest Income. Net interest expense decreased $0.9 million, or 16%, in 2016 compared to 2015 primarily due to lower amounts outstanding under our Revolving Credit Facility partially offset by unused commitment fees paid to our lenders. Interest expense as a percentage of total average debt outstanding increased from 3.6% in 2015 to 6.5% in 2016 due to an increased proportion of interest expense associated with unused commitment fees as a result of lower average borrowings outstanding under our Revolving Credit Facility.
 
Income Tax Benefit (Provision). Our income tax provision for the year ended December 31, 2016 was an income tax benefit of $26.9 million, or 36.7% of pretax losses, compared to income tax expense of $22.2 million, or 43.9% of pretax income, for the year ended December 31, 2015. The effective tax rate for the year ended December 31, 2015 was influenced by a $4.1 million tax valuation allowance recorded against certain of our deferred tax assets and a $3.6 million deferred tax adjustment for certain prior period non-deductible items.
 
Other Comprehensive Loss. Other comprehensive loss decreased from $28.6 million in 2015 to $19.6 million in 2016 due primarily to fluctuations in the currency exchange rates compared to the U.S. dollar for certain of the international operations of our reportable segments. For the year ended December 31, 2016, currency translation adjustments recognized as a component of other comprehensive loss were primarily attributable to the United Kingdom and Brazil. During 2016, the exchange rate of the British pound weakened compared to the U.S. dollar, while the exchange rate of the Brazilian real strengthened compared to the U.S. dollar. The British pound was impacted by the United Kingdom’s vote to exit the European Union in late June 2016.
 

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Liquidity, Capital Resources and Other Matters
 
Our primary liquidity needs are to fund operating and capital expenditures, which in the past have included expanding and upgrading our Offshore/Manufactured Products manufacturing facilities and equipment, replacing and increasing Completion Services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt, fund strategic business acquisitions and fund our stock repurchase program. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our credit facilities and capital market transactions.
 
As discussed under “Recent Developments” and below, we recently completed a number of strategic transactions in the furtherance of our growth strategy, which we believe should favorably impact our future results of operations and cash flows from operations as well as enhance our debt capital structure. See Note 18, “Subsequent Events,” to our Consolidated Financial Statements included in the Annual Report on Form 10‑K for additional information with respect to our acquisition of GEODynamics on January 12, 2018, our issuance of $200.0 million in principal amount of the Notes and an amendment of our Revolving Credit Facility extending its maturity to January 2022.
 
Operating Activities
 
Cash flows totaling $95.4 million were provided by operations during the year ended December 31, 2017 compared to $149.3 million provided by operations during the year ended December 31, 2016. During 2017 and 2016, $32.4 million and $90.3 million, respectively, was provided from net working capital reductions, which included decreases in accounts receivable and inventories.
 
Investing Activities
 
A total of $47.6 million in cash was used in investing activities during the year ended December 31, 2017, compared to $29.3 million used during the year ended December 31, 2016. Capital expenditures totaled $35.2 million and $29.7 million during the years ended December 31, 2017 and 2016, respectively. Capital expenditures in both years consisted principally of purchases of Completion Services equipment, expansion and upgrading of our Offshore/Manufactured Products segment facilities and various other capital spending initiatives. During 2017, we also invested $12.9 million within our Offshore/Manufactured Products segment to acquire complementary intellectual property and assets to expand our global crane manufacturing and service operations as well as our riser testing, inspection and repair service offerings.
 
On January 12, 2018, we acquired GEODynamics for a purchase price consisting of (i) $295 million in cash (net of cash acquired), which we funded through borrowings under our Revolving Credit Facility, (ii) approximately 8.66 million shares of our common stock (having a market value of approximately $295 million as of the closing date) and (iii) an unsecured $25 million promissory note.
 
We expect to spend between $60 million and $70 million in total capital expenditures during 2018 to upgrade and maintain our Offshore/Manufactured Products facilities and equipment, to replace and upgrade our Completion Services equipment, to expand and maintain GEODynamics facilities and equipment and to fund various other capital spending projects. Whether planned expenditures will actually be spent in 2018 depends on industry conditions, project approvals and schedules, vendor delivery timing, free cash flow generation and careful monitoring of our levels of liquidity. We plan to fund these capital expenditures with available cash, internally generated funds and borrowings under our Amended Revolving Credit Facility. The foregoing capital expenditure expectations do not include any funds that might be spent on future strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.
 
At December 31, 2017, we had cash totaling $53.5 million, of which $48.1 million was held by our international subsidiaries. With the enactment of Tax Reform Legislation on December 22, 2017, we expect to use a portion of the cash held by our international subsidiaries to reduce borrowings in 2018 without triggering any incremental tax expense.
 
Financing Activities
 
Net cash of $65.1 million was used in financing activities during the year ended December 31, 2017, primarily attributable to the net repayment of $42.2 million in borrowings under the Revolving Credit Facility and repurchases of our common stock totaling $16.3 million. Net cash of $84.9 million was used in financing activities during the year ended December 31, 2016, primarily associated with the net repayment of $80.7 million in borrowings under the Revolving Credit Facility.
 

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On January 12, 2018, we partially funded the GEODynamics Acquisition through borrowings available under our Revolving Credit Facility. On January 30, 2018, we issued $200.0 million in principal amount of our Notes and entered into our Amended Revolving Credit Facility, to extend the maturity of the facility to January 2022 and provide for total lender commitments of $350 million. Net proceeds from the Notes offering of approximately $194.0 million, after deducting discounts and estimated expenses, were used to repay a portion of amounts outstanding under the Revolving Credit Facility.
 
We believe that cash on hand, cash flow from operations and available borrowings under our Amended Revolving Credit Facility will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and any issuance of additional equity securities could result in significant dilution to stockholders.
 
Revolving Credit Facility. Our Revolving Credit Facility was governed by the Credit Agreement dated as of May 28, 2014, as amended, (the "Credit Agreement") by and among the Company, the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent, the Swing Line Lender and an Issuing Bank, Royal Bank of Canada, as syndication agent, and Compass Bank, as documentation agent. As of December 31, 2017, our Revolving Credit Facility was scheduled to mature on May 28, 2019. As of December 31, 2017, we had no borrowings outstanding under the Credit Agreement and we had $21.2 million of outstanding letters of credit, leaving $159.3 million available to be drawn under the Revolving Credit Facility. During 2017, our applicable margin over LIBOR was 1.50%. We also paid a quarterly commitment fee of 0.375% during 2017. Interest expense as a percentage of average total debt outstanding increased from 6.5% in 2016 to 17.3% in 2017. The increase in the weighted average interest rate was attributable to an increased proportion of interest expense associated with unused commitment fees, lower average borrowings outstanding under our Revolving Credit Facility, and non-cash amortization of debt issuance costs.
 
We amended and restated our Credit Agreement on January 30, 2018 with Wells Fargo Bank, N.A., as administrative agent for the lenders party thereto and collateral agent for the secured parties thereunder, and the lenders and other the financial institutions from time to time party thereto (the “Amended Credit Agreement”). The Amended Credit Agreement governs our Amended Revolving Credit Facility. The Amended Revolving Credit Facility provides for up to $350 million in lender commitments and matures in January 2022. Under our Amended Revolving Credit Facility, $50 million is available for the issuance of letters of credit.
 
Amounts outstanding under our Amended Revolving Credit Facility bear interest at LIBOR plus a margin of 1.75% to 3.00%, or at a base rate plus a margin of 0.75% to 2.00%, in each case based on a ratio of our total net funded debt to consolidated EBITDA (as defined in the Amended Credit Agreement). We must also pay a quarterly commitment fee of 0.25% to 0.50%, based on our ratio of total net funded debt to consolidated EBITDA, on the unused commitments under the Amended Credit Agreement.
 
The Amended Credit Agreement contains customary financial covenants and restrictions. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA to consolidated interest expense, of at least 3.0 to 1.0, a maximum senior secured leverage ratio, defined as the ratio of senior secured debt to consolidated EBITDA, of no greater than 2.25 to 1.0 and a total net leverage ratio, defined as the ratio of total net funded debt to consolidated EBITDA, of no greater than 4.0 to 1.0 through the fiscal quarter ending December 31, 2018 and no greater than 3.75 to 1.0 thereafter. Our financial covenants will give pro forma effect to the issuance of the Notes, the acquired businesses and the annualization of EBITDA for the acquired businesses for the fiscal quarters ending March 31, 2018 and June 30, 2018.
 
Each of the factors considered in the calculations of these ratios are defined in the Amended Credit Agreement. Consolidated EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of December 31, 2017, we were in compliance with our debt covenants and expect to continue to be in compliance throughout 2018.
 
Borrowings under the Amended Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Amended Credit Agreement are guaranteed by our significant domestic subsidiaries.
 

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Under the Amended Credit Agreement, the occurrence of specified change of control events involving our Company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facility and cause it to become immediately due and payable in full.
 
As of January 31, 2018, we had $97.0 million outstanding under the Amended Revolving Credit Facility and an additional $21.2 million of outstanding letters of credit.
 
1.50% Convertible Senior Notes. On January 30, 2018, we issued $200.0 million aggregate principal amount of the Notes pursuant to an indenture, dated as of January 30, 2018 (the “Indenture”), between us and Wells Fargo Bank, N.A., as trustee. Net proceeds, after deducting discounts and expenses, were approximately $194.0 million. We used the net proceeds to repay a portion of the outstanding borrowings under the Revolving Credit Facility.
 
The Notes bear interest at a rate of 1.50% per year until maturity. Interest is payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. In addition, additional interest and special interest may accrue on the Notes under certain circumstances as described in the Indenture. The Notes will mature on February 15, 2023, unless earlier repurchased, redeemed or converted. The initial conversion rate is 22.2748 shares of our common stock per $1,000 principal amount of Notes (equivalent to an initial conversion price of approximately $44.89 per share of common stock). The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the Indenture.
 
Noteholders may convert their Notes, at their option, upon certain circumstances as described in the Indenture. We will settle conversions by paying or delivering, as applicable, cash, shares of common stock or a combination of cash and shares of common stock, at our election, based on the applicable conversion rate(s). If we elect to deliver cash or a combination of cash and shares of common stock, then the consideration due upon conversion will be based on a defined observation period.
 
The Notes will be redeemable, in whole or in part, at our option at any time, and from time to time, on or after February 15, 2021, at a cash redemption price equal to the principal amount of the Notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, but only if the last reported sale price per share of common stock exceeds 130% of the conversion price on each of at least 20 trading days during the 30 consecutive trading days ending on, and including, the trading day immediately before the date we send the related redemption notice.
 
If specified change in control events involving the Company as defined in the Indenture occur, then noteholders may require us to repurchase their Notes at a cash repurchase price equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest.
 
The initial carrying amount of the Notes recorded in our consolidated balance sheet in 2018 will be less than the $200.0 million in principal amount of the Notes, in accordance with applicable accounting principles, reflective of the estimated fair value of a similar debt instrument that does not have a conversion feature. We will record this difference as a debt discount, which will be amortized as interest expense over the term of the Notes, with a similar amount allocated to additional paid-in capital. As a result of this amortization, the interest expense we recognize related to the Notes for accounting purposes will be greater than the cash interest payments we will pay on the Notes.
 
Stock Repurchase Program. On July 29, 2015, our Board of Directors approved the termination of our then existing share repurchase program and authorized a new program providing for the repurchase of up to $150.0 million of our common stock, which, following extension, was scheduled to expire on July 29, 2017. On July 26, 2017, our Board of Directors extended the share repurchase program for one year to July 29, 2018. During 2017, we repurchased 562 thousand shares of common stock under the program at a total cost of $16.3 million. No shares of our common stock were repurchased under the program in 2016. During 2015, a total of $105.9 million of our stock (2.7 million shares) were repurchased under these programs. The amount remaining under our current share repurchase authorization as of December 31, 2017 was $120.5 million. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate.
 

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Contractual Obligations. The following summarizes our contractual obligations at December 31, 2017, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):
 
Payments due by period
 
Total
 
Less than 1 year
 
1 - 3 years
 
3 - 5 years
 
More than 5 years
Contractual obligations (1)
 
 
 
 
 
 
 
 
 
Revolving Credit Facility
$

 
$

 
$

 
$

 
$

1.50% Convertible Senior Notes

 

 

 

 

Promissory note

 

 

 

 

Other debt and capital leases
5,281

 
411

 
862

 
772

 
3,236

Purchase obligations
41,236

 
41,236