ois20161231_10k.htm

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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.

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, 2016, the aggregate market value of the voting and non-voting common stock of the registrant held by non-affiliates of the registrant was $1,616,900,263.

As of February 10, 2017, the number of shares of common stock outstanding was 51,372,628.

Portions of the registrant's Definitive Proxy Statement for the 2017 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.

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, or our management, express an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. 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:

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 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.

Oil States International, Inc., through its subsidiaries, is a leading provider of specialty products and services to oil and natural gas related companies throughout the world. We are a technology-focused, pure-play energy services company operating in some of the world's most active oil and natural gas producing regions, including onshore and offshore United States, Canada, West Africa, the Middle East, the North Sea, South America and Southeast and Central Asia. 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. We operate through two business segments – Offshore Products and Well Site Services – and have established a leadership position in certain of our product or service offerings in each segment. In this Annual Report on Form 10-K, references to the "Company" or “Oil States” or to "we," "us," "our," and similar terms are to Oil States International, Inc. and its consolidated subsidiaries.

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 “Commission”). 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 Commission. The filings are also available through the Commission at the Commission's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. 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 and Corporate Governance Committee) may also be viewed at the Company's website. The financial code of ethics applies to our principal executive officer, principal financial officer, principal accounting officer and other senior officers. Copies of such documents will be 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.

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 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.”

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 16 to the Consolidated Financial Statements included in “Part II, Item 8. Financial Statements and Supplementary Data” for financial information by segment and a geographical breakout of revenues and long-lived assets for each of the three years in the period ended December 31, 2016. 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 throughout 2015 and most of 2016. This industry downturn was characterized by materially reduced capital investments made by our customers, rapidly declining rig counts, declining 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 2016. This significant activity decline had a material negative effect on the results of our Well Site Services segment in 2015 and 2016. Our Offshore Products segment was also negatively impacted but our results declined at a slower pace given high levels of backlog that existed at the beginning of 2014. Despite a slower decline in revenue and operating income when compared to our Well Site Services segment, our Offshore Products backlog declined materially from 2014 to 2016. 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.”

Demand for the products and services supplied by our Offshore Products segment is generally driven by the longer-term outlook for commodity prices, and to a lesser extent, 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 Products segment. However, the significant decline in crude oil prices since 2014 caused exploration and production companies to reevaluate their future capital expenditures in regards to deepwater projects given that certain of these deepwater projects 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 Products segment continued during 2015 and 2016, albeit at a substantially slower pace. Accordingly, backlog in our Offshore Products 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.

Lower commodity prices have, and may continue to have, a negative impact on the cash flows of our customers forcing them to reduce or delay capital expenditures and control costs, which have, and may continue to have, an adverse effect on our results of operations, cash flows and financial condition. Global deepwater spending has been and could continue to be negatively impacted as a result which may lead to further backlog declines in our Offshore Products segment in the near-term along with reduced revenues and profitability.

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 and have been significantly negatively affected by the material decline in crude oil prices that began in 2014 and continued throughout 2015 and most of 2016.

Over the past several years, our industry experienced a shift in customer spending from natural gas exploration and development to crude oil and liquids-rich exploration and development in the North American shale plays utilizing horizontal drilling and completion techniques. 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. According to rig count data published by Baker Hughes Incorporated, 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 525 rigs as of December 31, 2016 (with the U.S. oil rig count bottoming at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn). As of December 31, 2016, oil-directed drilling accounted for 80% of the total U.S. rig count – with the remaining balance natural gas related. Although the U.S. land rig count has increased 259 rigs, or 69%, since troughing in May of 2016, activity continues to remain at historically low levels. Unless commodity prices continue to improve, we expect that the rig count and demand for services from our customers of our Well Site Services segment will continue to remain tempered in the near term.

In response to the adverse effects in 2015 and 2016 of the materially lower commodity prices on our results of operations, cash flows and financial position, the Company implemented a number of cost-saving measures, including the closing of underperforming Completion Services’ locations and company-wide headcount reductions that totaled approximately 47% since the beginning of 2015.

See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Macroeconomic Environment.”

For the years ended, December 31, 2016, 2015 and 2014, our Offshore Products segment generated approximately 73%, 66% and 53%, respectively, of our revenue and 94%, 74% and 49%, 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, blow-out preventer stack integration, specialty welding, fabrication, cladding and machining services, offshore installation services and inspection and repair services. In addition, we design, manufacture and market numerous shorter-cycle 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 Products segment in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Oklahoma City and Tulsa, Oklahoma; the United Kingdom; Brazil; Singapore; Thailand; Vietnam; and India.

The market for Offshore Products centers primarily on the development of infrastructure for offshore production facilities and their subsequent operations, exploration and drilling activities as well as 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 products and services to land-based drilling and completion markets is driven by the level and complexity of drilling, completion and workover activity, particularly in North America.

In operation for 75 years, our Offshore 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 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. 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 areas. 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).

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:

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:

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^TM connector technology with the design and manufacture of multiple riser systems. The unique Merlin^TM 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 a par with those of our Tension Leg Elements (“TLE”) connectors. The connector can be welded or machined directly onto upset riser pipe and provide sufficient material to perform "re-cuts" after extended service. Our marine riser offers 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 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:

Other Products & Services. Our Offshore 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:

Backlog. Offshore Products’ backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. Backlog in our Offshore Products segment was $199 million at December 31, 2016, compared to $340 million at December 31, 2015 and $490 million at December 31, 2014. We expect approximately 70% of our backlog at December 31, 2016 to be recognized as revenue during 2017. 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 $21.1 million during 2015 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 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.

Our Offshore 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 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.

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. No customer represented more than 10% of our total consolidated revenue in any period presented. Our main competitors in this segment include Cameron International Corporation (now a division of Schlumberger Limited), FMC Technologies, Inc., Dril-Quip, Inc., National Oilwell Varco, Inc., GE Oil & Gas (a division of General Electric Company) and Liebherr Cranes, Inc.

For the years ended December 31, 2016, 2015 and 2014, our Well Site Services segment generated approximately 27%, 34% and 47%, respectively, of our revenue and 6%, 26% and 51%, respectively, of our gross profit. 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.

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.

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:

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, 2016, 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 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, 2016, 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 of 33% in 2015 and 12% in 2016 due to lower crude oil prices and a shift by customers to newer, larger and higher horsepower rigs needed to drill extended depths and horizontal wells. 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.

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.

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 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.

As of December 31, 2016, the Company employed 2,821 full-time employees on a consolidated basis, 40% of whom are in our Well Site Services segment, 57% of whom are in our Offshore Products segment and 3% of whom are in our corporate headquarters. This compares to a total of 3,586 full-time employees as of December 31, 2015. Company-wide headcount has been reduced by approximately 47% between December 31, 2014 and December 31, 2016. We were party to collective bargaining agreements covering a small number of employees located in Argentina and the United Kingdom as of December 31, 2016. We believe we have good labor relations with our employees.

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”) 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) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations.

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:

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. See Risk Factors under Part I, Item 1A of this Form 10-K for further discussion on hydraulic fracturing; induced seismicity regulatory developments; climate change, including methane or other GHG emissions; 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 new standards continue to evolve.

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 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 as well as claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, including administrative, civil, and criminal penalties.

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 caused a reduction in most of our customers’ drilling, completion and other production activities and related spending on our products and services in 2015 and 2016. 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 services, particularly customers of our Well Site Services segment. Although oil and natural gas prices improved somewhat in late 2016, these price improvements have not resulted in widespread 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 reductions in the prices we charge, could continue and accelerate through 2017 and beyond. 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.

Conditions in our industry are beginning to improve, particularly in the shale resource plays in the United States, and 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, an inability to meet financial ratios contained in our debt agreements, a need to reduce our capital spending and other similar impacts. For example, under our Credit Agreement, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA to consolidated interest expense of at least 3.0 to 1.0 and a maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. As of December 31, 2016, we had $42.2 million in borrowings outstanding under the Credit Agreement and $30.7 million of outstanding letters of credit, leaving $153.1 million available to be drawn under our revolving credit facility. The total amount available to be drawn under our revolving credit facility was less than the lender commitments as of December 31, 2016, due to the maximum leverage ratio covenant in our revolving credit facility which serves to limit borrowings, and such availability is expected to be further reduced during 2017 and potentially beyond, due to reductions in our trailing twelve-month EBITDA (as defined in the Credit Agreement). As more fully disclosed in Note 10, Long-term Debt, 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 2017.

Many factors affect the supply of and demand for oil and natural gas and, therefore, influence product prices, including:

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 in 2016. As a result, many of our customers announced reductions or delays in their capital spending in 2015 and 2016, which reduced the demand for our products and services and exerted downward pressure on the prices of our products and services. Although some of our customers have increased their 2017 capital expenditure budgets, these customers are still spending significantly less than 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 and our customers’ capital spending materially 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:

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

As of December 31, 2016, goodwill represented 19% of our total assets. We have recorded goodwill because we paid more for some of our businesses that we acquired than the fair market value of the tangible and separately measurable intangible net assets of those businesses. We are required to periodically review the goodwill of our applicable reporting units (Completion Services and Offshore 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:

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 certain portion of our Completion Services and Offshore 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 permeabilities, such as shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. Hydraulic fracturing is currently generally exempt from regulation under the SDWA’s 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 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 final CAA regulations in 2012 that include New Source Performance Standards (“NSPS”) for completions of hydraulically fractured natural gas wells, compressors, controls, dehydrators, storage tanks, natural gas processing plants, and certain other equipment. In June 2016, the EPA published final rules establishing new emissions standards for methane and additional standards for volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities and is formally seeking additional information from oil and natural gas exploration and production operators as necessary to eventually expand these final rules to include existing equipment and processes. In addition, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking 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 but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision is currently being appealed by the federal government. 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 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.

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 that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or may have been, the likely cause of 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 issued new rules for wastewater disposal wells in 2014 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 adopted similar rules in 2014. In addition, ongoing lawsuits allege 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 BOEM and the BSEE 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 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. In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL”) in July 2016 that 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. These existing rules, or 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 elects 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. 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 29% (13% excluding the United Kingdom and Canada) of our consolidated revenue in the year ended December 31, 2016. Risks associated with our operations in foreign areas include, but are not limited to:

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 9% of the Company’s consolidated revenues in 2016 and 5% in 2015.

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, or 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.

The announcement of Brexit caused significant volatility in global stock markets and currency exchange rate fluctuations that resulted in the strengthening of the U.S. dollar against foreign currencies in which we conduct business. As of December 31, 2016, the exchange rate of the British pound compared to the U.S. dollar weakened by 16% compared to the exchange rate at December 31, 2015. Any further volatility may adversely affect our results of operations. Asset valuations, currency exchange rates and credit ratings may be especially subject to increased market volatility. Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, increased from $50.7 million at December 31, 2015 to $70.3 million at December 31, 2016 due to changes in currency exchange rates, largely the British pound. The announcement of Brexit and the withdrawal of the U.K. from the European Union may also create global economic uncertainty, which may cause our customers to closely monitor their costs and reduce their spending budgets for our products and services. 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:

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 emissions of 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 NSPS, known as Subpart Quad OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. Moreover, in November 2016, the EPA issued a final Information Collection Request (“ICR”) seeking additional information from oil and gas producing operators as necessary to expand these standards to include existing equipment and processes. 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 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.

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.

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 (“FWS”) 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.

Changes to tax laws and regulations could materially, negatively impact the Company by increasing the costs of doing business for our customers thereby decreasing the demand for our products and services.

Changes in various laws and regulations could have a material negative effect on our customers, resulting in lower demand for our products and services. In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws including, but not limited to:

Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect.

In addition, the Republican members of the House Ways and Means Committee in June 2016 released a Blueprint for a pro-growth tax code which, among other provisions, includes a destination-based business cash flow tax. This proposal includes border adjustments, under which products, services and intangibles that are exported from the United States would not be subject to U.S. tax, but products, services and intangibles that a business imports into the United States would be subject to U.S. tax. This proposal currently is under active consideration in Congress as part of the development of potential comprehensive tax reform legislation. If enacted, such proposal could serve to delay access to or increase the costs of goods and services that we import.

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 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.

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. However, we may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders.

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

Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and 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.

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:

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.

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.

While no customer accounted for more than 10% of our consolidated revenues in 2016, 2015 or 2014, we depend on several significant customers in each of our business segments. 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.

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

The market price of common stock of companies engaged in the oil and natural gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly in the past, and we expect it to continue to remain highly volatile given the cyclical nature of our industry.

We may assume contractual risks in developing, manufacturing and delivering products in our Offshore Products business segment.

Many of our products from our Offshore Products segment are ordered by customers under frame agreements or project-specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. 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 Products segment is subject to unexpected adjustments and cancellations and is, therefore, an imperfect indicator of our future revenues and earnings.

The revenues projected in our Offshore Products segment backlog may not be realized or, if realized, may not result in profits. Because of potential changes in the scope or schedule of our customers’ projects, we cannot predict with certainty when or if backlog will be realized. 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 cancelled. While backlog cancellations have not been significant in the past, we incurred cancellations totaling $21.1 million during 2015 and $3.7 million during 2016. If commodity prices do not improve, we may incur additional cancellations or experience continued declines in our backlog during 2017. 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.

Many of the products that we sell, especially in our Offshore Products segment, are complex and highly engineered, and often must perform in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize, and enhance these products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. During periods of increased activity, the demand for skilled workers is high, and the supply is limited. 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 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 were 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 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 rely on a variety of intellectual property rights that we use in our Offshore Products and Completion Services businesses, particularly our patents relating to our FlexJoint^® and Merlin™ technology and intervention and downhole extended-reach tools (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 limits the scope of claims in a patent or fails to recognize our trade secret rights, our competitive advantages could be significantly reduced in the relevant technology, allowing competition for our customer base to increase. In addition, the laws of some foreign countries in which our products and services may be sold do not protect intellectual property rights to the same extent as the laws of the United States. The failure of our Company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position.

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

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

We spun off our accommodations business to a stand-alone, publicly traded corporation (“Civeo”) 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 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 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 Products – Rio de Janeiro and Macae, Brazil; Aberdeen, Bathgate and West Lothian, Scotland; Barrow-in-Furness, England; Rayong, Thailand; Singapore; Navi Mumbai, India; 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, Odessa, Texas; New Iberia Houma, Louisiana; Casper and Rock Springs, Wyoming; Williston, North Dakota and Renton, Washington.

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.

Information regarding legal proceedings is set forth in Note 14 of the Consolidated Financial Statements and is incorporated herein by reference.

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

Our authorized common stock consists of 200,000,000 shares of common stock. There were 51,372,628 shares of common stock outstanding as of February 10, 2017. The approximate number of record holders of our common stock as of February 10, 2017 was 20. 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 10, 2017 was $39.75 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):

We have not declared or paid any cash dividends on our common stock since our initial public offering in 2001 and our existing 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.

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, 2011 to December 31, 2016. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2011 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.

*$100 invested on December 31, 2011 in stock or index, including reinvestment of dividends. Fiscal year ended December 31.

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, 2016. 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.

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):

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.

Due to the spin-off on May 30, 2014 of our accommodations business into a stand-alone, publicly traded corporation (“Civeo Corporation”, or “Civeo”) through a tax-free distribution of the accommodations business to the Company’s stockholders (the “Spin-Off”), and the sale of our tubular services business on September 6, 2013, both of which are reported as discontinued operations, our management believes that income from continuing operations is more representative of the Company’s current business environment and focus. The terms “earnings” and “loss” as used in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” refer to income (loss) from continuing operations.

We provide a broad range of products and services to the oil and gas industry through our Offshore 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.

A severe industry downturn started in the second half of 2014 and continued throughout 2015 and most of 2016, driven by global economic uncertainties and high levels of global oil production. As shown in the table below, significant downward crude oil price volatility began in late 2014 with Intercontinental Exchange Brent (“Brent”) crude oil declining from an average of $102 per barrel in the third quarter of 2014 to an average of $34 in the first quarter of 2016 (a level last seen in 2004). The sustained material decrease in crude oil prices since 2014 is 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 the Organization of Petroleum Exporting Countries (“OPEC”) increasing its production. 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 have been partially offset by growth in global crude oil demand. The combination of these factors caused a global supply and demand imbalance for crude oil which, along with concerns regarding the potential effects on energy demand stemming from the diminished growth outlook in China and other emerging markets, and the anticipated and actual supply increases related to the lifting of sanctions against Iran (sanctions were lifted in January 2016), 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 leading to some recovery in crude oil prices in recent quarters. On November 30, 2016, OPEC agreed to production cuts 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 improved to average $49 per barrel in the fourth quarter of 2016 and the average price of West Texas Intermediate (“WTI”) was also $49 per barrel in the fourth quarter of 2016. The improvement in oil prices is driven by the belief that OPEC and Russia, its key ally in the effort to stabilize the global crude oil market, are expected to be successful in cutting their production. U.S. oil price improvement is rapidly translating into increased drilling activity and higher oil output in U.S. shale play developments in areas, such as the Permian, Bakken and Niobrara basins. Spending in these regions, which began to improve in the second half of 2016 in response to higher crude oil prices, will influence the overall drilling and completion activity in the area and, therefore, the activity of our Well Site Services segment in 2017 and beyond. 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 majority of the activity of our Offshore 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 due to relatively high levels of global inventories, the potential for domestic crude oil production to increase, slowing growth rates in various global regions, 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 (which is occurring) or government instability in a major oil-producing nation, and energy demand were to continue to increase in the United States, India and China’s outlook for growth improves, a further recovery in WTI and Brent crude oil prices could occur. The International Energy Agency (“IEA”) calls for supply and demand to reach equilibrium by mid-2017. In any event, crude oil price improvements will depend upon a rebalancing of global supply and demand, with a corresponding 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.

Prices for natural gas in the United States averaged $2.52 per mmBtu in 2016, which compares to $2.62 per mmBtu in 2015 and $4.37 per mmBtu in 2014. The 2016 average price of $2.52 per mmBtu was the lowest annual average since 1999 – driven by a mild winter which caused inventory storage levels to rise to historic highs in the first quarter of 2016. Natural gas prices improved over the course of 2016 from an average of $1.99 per mmBtu in the first quarter to an average of $3.04 per mmBtu during the fourth quarter as a result of declining production, increased demand for natural gas to fuel electricity generation and colder temperatures in the Northern United States. Natural gas surpassed coal during 2014 as the largest energy source for generating electricity. Reflecting the impact of decreased production and higher demand for natural gas, inventories in the United States were 1% below the 5-year average at the end of 2016, which compares to 14% above the 5-year average at the end of 2015. 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 and the commissioning of a number of new, large LNG export facilities around the world. As a result of natural gas supply growth outpacing demand growth in the United States in recent years, natural gas prices continue to be weak and are expected to remain below levels considered economical for new investments in certain natural gas fields. 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 and natural gas pricing trends are as follows:

Demand for the products and services of our Offshore Products segment is driven by the longer-term outlook for commodity prices and, to a lesser extent, changes in land-based drilling and completion activity. Demand for the equipment and services of our Well Site Services segment responds to shorter-term movements in crude oil and natural gas prices and, specifically, changes in North American drilling and completion activity given the spot contract nature of our operations coupled with shorter cycles between drilling a well and bringing it on production. Other factors that can affect our business and financial results include but are not limited to the general global economic environment, competitive pricing pressures and regulatory changes in the United States and international markets.

Our Offshore Products segment provides 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 Products sales in 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. 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. We believe some of these deepwater projects once approved for development are, therefore, less susceptible to short-term fluctuations in the price of crude oil and natural gas given longer lead times associated with field development. However, the decline in crude oil prices that began in 2014 and continued throughout 2015 and into 2016, 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. Sales of products and services to the land-based drilling and completion markets are impacted by near-term fluctuations in commodity prices. Sales of these shorter-cycle products (such as valves and elastomer products) and services for this segment declined significantly in 2015 and 2016; however, demand for our elastomer products has increased in the second half of 2016 compared to levels of demand experienced in the first half of 2016 commensurate with the increase in the U.S. land rig count.

Our Offshore Products segment revenues and operating income declined at a slower pace than our Well Site Services segment given the high levels of backlog that existed at the beginning of 2014. Bidding and quoting activity, along with orders from customers, for our Offshore Products segment continued during 2015 and 2016, albeit at a much slower pace. Accordingly, backlog in our Offshore Products 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 low commodity price environment.

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 our Well Site Services segment results, are particularly sensitive to near-term fluctuations in commodity prices given the call-out nature of our operations in this segment and have, therefore, been significantly negatively affected by the material decline in crude oil prices and customer spending from 2014 to the second half of 2016. However, U.S. oil price improvement is rapidly translating into increased drilling and completion activity in the U.S. shale play regions.

Over the past several years, our industry experienced a shift in customer spending from natural gas exploration and development to crude oil and liquids-rich exploration and development in the North American shale plays utilizing horizontal drilling and completion techniques. 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. According to rig count data published by Baker Hughes Incorporated, 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. The U.S. oil rig count troughed at 316 rigs in May 2016, which was the lowest oil rig count during this current cyclical downturn and has increased gradually to 525 rigs as of December 31, 2016. As of December 31, 2016, the oil-directed drilling accounted for 80% of the total U.S. rig count – with the balance natural gas related. Although the U.S. land rig count has increased 259 rigs, or 69%, since troughing in May of 2016, activity continues to remain at historically low levels. Unless commodity prices continue to gradually improve, we expect that the rig count and demand from our customers for services provided by our Well Site Services segment will continue to be tempered in the near term.

In our Well Site Services segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our Completion Services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the Completion Services business is dependent primarily upon the level and complexity of drilling, completion, and workover activity throughout North America. Well complexity has increased 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. Demand for our Drilling Services operations is driven by land drilling activity in our primary drilling markets of the Permian Basin in West Texas, where we primarily 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 expected to be drilled, total footage expected to be drilled, and the number of drilled wells that are completed. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.

The average North American rig count in 2016 declined 529 rigs, or 45%, from the level reported in 2015, in response to the sustained impact of significantly lower crude oil and natural gas prices from the levels experienced in 2014.

Exacerbating the steep declines in drilling activity, many of our exploration and production customers had deferred well completions. These deferred completions are referred to in the industry as drilled but uncompleted wells (or “DUCs”). Motivation on the part of our customers to defer completions was generally driven by the need to preserve cash in a weak commodity price environment and/or the desire to produce reserves at a later date with expectations that commodity prices would improve and/or completion costs would continue to decline (although our customers have begun to complete their backlog of uncompleted wells). Given our Well Site Services segment’s exposure to the level of completion activity, an increase in the number of DUCs will have a negative impact on our results of operations.

Reduced demand for our products and services, coupled with a reduction in the prices we charge our customers for our services, particularly customers of our Well Site Services segment, has adversely affected our results of operations, cash flows and financial position as of and for the year ended 2016. If the current pricing environment for crude oil and natural gas does not continue to improve, or declines, our customers may be required to further reduce their capital expenditures, causing further 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 due to the commodity price declines and the fact that, due to the passage of time, many customers have less production hedged and, thus, are receiving spot prices for a greater percentage of their production. As a result of this industry downturn, many customers experienced a significant reduction in liquidity with challenges accessing the capital and debt markets through the end of 2015. There have been several exploration and production companies who have declared bankruptcy in 2015 and 2016, or have had to exchange equity for the forgiveness of debt, and others who have been forced to sell assets in an effort to preserve liquidity. However, during 2016, access to the capital and debt markets improved significantly for certain customers. A continuation of these adverse conditions could affect certain of our customers’ ability to pay or otherwise perform their obligations to us. Declines in the demand for, and prices of, our products and services or the inability or failure of our customers to meet their obligations to us, or their insolvency or liquidation, could require us to incur asset impairment charges, and/or write down the value of our goodwill, and may otherwise adversely impact our results of operations and our cash flows and financial position.

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. We expect to spend between $40 to $45 million in capital expenditures for fiscal 2017 to upgrade and maintain our Offshore Products facilities, to replace and upgrade our Completion Services equipment and to fund various other capital spending projects. We plan to fund our capital expenditures with available cash, internally generated funds, and borrowings under our revolving credit facility. In our Well Site Services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on our evaluation of both the market outlook and industry fundamentals.

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 complimentary acquisitions in each of our business segments in recent years. We acquired four businesses for a total of $158.3 million in cash during the 2012 through 2016 timeframe.

For example, on January 2, 2015, our Offshore Products segment acquired Montgomery Machine Company, Inc. (“MMC”), which combines machining and proprietary cladding technology and services to the manufacture of high-specification components for the offshore capital equipment industry on a global basis. We believe that the acquisition of MMC has strengthened our Offshore Products segment’s position as a supplier of subsea components with enhanced capabilities, proprietary technology and logistical advantages. Total transaction consideration was $33.4 million, net of cash acquired.

We manage and measure our business performance in two distinct operating segments: Well Site Services and Offshore Products. Selected financial information by business segment for years ended December 31, 2016, 2015 and 2014 is summarized below (dollars in thousands):

Net loss from continuing operations attributable to the Company 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 attributable to the Company 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 the Company’s 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 Offshore 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 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 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 (“SG&A”) 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.

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 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). The Company’s 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 the Company’s 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, Brazil and Canada. As of December 31, 2016, the exchange rate of the British pound compared to the U.S. dollar weakened by 16% compared to the exchange rate at December 31, 2015, while the exchange rates of the Brazilian real and Canadian dollar compared to the U.S. dollar strengthened by 22% and 3%, respectively, during the same period.

We reported net income from continuing operations attributable to the Company for the year ended December 31, 2015 of $28.4 million, or $0.55 per diluted share, which included $6.4 million of severance and other downsizing charges, a $3.4 million leasehold restoration provision for one of our Offshore Products U.K. facilities included in “Depreciation and amortization expense,” and a higher effective tax rate driven primarily by a $4.1 million valuation allowance recorded against the Company’s tax loss carryforwards in various international jurisdictions, and $3.6 million in tax adjustments primarily related to non-deductible items. Excluding these charges in 2015, net income from continuing operations would have been $43.1 million, or $0.84 per diluted share. These results compare to net income from continuing operations attributable to the Company of $127.2 million, or $2.35 per diluted share, reported for the year ended December 31, 2014, including a loss on extinguishment of debt of $100.4 million, or $1.21 per diluted share, and $11.2 million, or $0.14 per diluted share, of transaction costs included in “Other operating expense” and SG&A expenses primarily related to the Spin-Off. Excluding these significant charges in 2014, net income from continuing operations would have been $199.6 million, or $3.69 per diluted share.

Revenues. Consolidated revenues decreased $719.6 million, or 40%, in 2015 compared to 2014.

Our Well Site Services segment revenues decreased $482.1 million, or 56%, in 2015 compared to 2014 due to decreases in both Completion Services and Drilling Services revenues. Our Completion Services revenues decreased $348.8 million, or 53%, in 2015 compared to 2014, primarily due to a 38% decrease in the number of service tickets completed as a result of decreased activity in the U.S. shale basins and a 25% decrease in our revenue per Completion Services job due to pricing pressure from our customers and competitors. Our Drilling Services revenues decreased $133.3 million, or 66%, in 2015 compared to 2014 primarily as a result of significantly decreased utilization of our drilling rigs from an average of 87% during 2014 to an average of 33% in 2015 primarily due to the weak commodity price environment.

Our Offshore Products segment revenues decreased $237.5 million, or 25%, in 2015 compared to 2014. This decrease was primarily the result of lower contributions from essentially all product and service lines, especially drilling products and shorter cycle businesses such as elastomer products and valves, coupled with reduced service activities and a backlog that trended lower during 2015.

Cost of Sales and Service. Our consolidated cost of sales and services decreased $420.2 million, or 35%, in 2015 compared to 2014 as a result of decreased cost of sales and services at our Well Site Services and Offshore Products segments of $250.6 million, or 46%, and $169.6 million, or 26%, respectively. With cost of sales and service decreasing at a slower rate than our revenues, consolidated gross profit as a percentage of revenues decreased from 34% in 2014 to 29% in 2015 primarily due to lower margins realized in our Well Site Services segment in 2015.

Our Well Site Services segment cost of services decreased $250.6 million, or 46%, in 2015 compared to 2014 as a result of a $165.5 million, or 41%, decrease in Completion Services cost of services and a $85.1 million, or 60%, 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 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 37% in 2014 to 22% in 2015. Our Completion Services gross profit as a percentage of revenues decreased from 39% in 2014 to 23% in 2015 primarily due to the decline in revenues. Our Drilling Services gross profit as a percentage of revenues decreased from 30% in 2014 to 17% in 2015 primarily due to decreased rig utilization and cost absorption.

Our Offshore Products segment cost of products and services decreased $169.6 million, or 26%, in 2015 compared to 2014 in correlation with the decrease in revenues. Gross profit as a percentage of revenues remained generally constant (31% in 2014 compared to 32% in 2015). The improvement in gross profit year-over-year is due to strong project execution on several jobs combined with favorable cost adjustments (including favorable percentage-of-completion adjustments) as we lowered our overall cost structure.

Selling, General and Administrative Expenses. Selling, general and administrative expense decreased $36.8 million, or 22%, in 2015 compared to 2014 largely due to decreased compensation including short-term incentive compensation, wages and benefits and stock compensation expense coupled with a decrease in commissions and bad debt expense.

Depreciation and Amortization. Depreciation and amortization expense increased $6.5 million, or 5%, in 2015 compared to 2014 due to capital expenditures made during the previous twelve months across all segments of our Company, the $3.4 million leasehold restoration provision for one of our Offshore Products U.K. facilities, along with increased depreciation and amortization expense related to the MMC acquisition which closed at the beginning of the first quarter of 2015.

Other Operating (Income) Expense. Other operating (income) expense moved from other operating expense of $9.3 million in 2014 to other operating income of $4.6 million in 2015 primarily due to transaction costs incurred in 2014 in connection with the Spin-Off totaling $11.0 million and $3.7 million of foreign currency exchange gains in 2015.

Operating Income (Loss). Consolidated operating income (loss) decreased $255.2 million, or 82%, in 2015 compared to 2014 primarily as a result of decreases in operating income from our Well Site Services segment of $222.5 million resulting from decreased revenues caused by industry activity declines, and a $52.4 million decrease in Offshore Products operating income. Corporate expenses were $47.2 million in 2015, compared to $68.2 million in 2014.

Interest Expense and Interest Income. Net interest expense decreased $10.7 million, or 65%, in 2015 compared to 2014 primarily due to the Company’s repurchase of the remaining $966.0 million aggregate principal amount of our 6 1/2% and 5 1/8% Notes in the second quarter of 2014, partially offset by increased amounts outstanding under our bank credit facility coupled with unused commitment fees paid to our lenders. The weighted average interest rate on the Company’s total outstanding debt decreased from 6.0% in 2014 to 3.6% in 2015 primarily due to the repurchase of the 6 1/2% and 5 1/8% Notes in the second quarter of 2014.

Loss on Extinguishment of Debt. 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, resulting in a loss of $96.7 million consisting of the premium paid over book value for the Notes and the write-off of associated unamortized deferred financing costs. In addition, as a result of the refinancing of our bank credit facility in 2014, we recognized a loss of $3.7 million (net of $1.8 million allocated to discontinued operations for the Canadian portion of the facility) from the write-off of unamortized deferred financing costs on our existing credit facility.

Income Tax Benefit (Provision). The Company’s income tax provision for 2015 totaled $22.2 million, or 43.9% of pretax income, compared to income tax expense of $69.1 million, or 35.2% of pretax income, for 2014. The increase in the effective tax rate from the prior year was largely the result of a $4.1 million valuation allowance recorded against the Company’s tax loss carryforwards in various international jurisdictions, and $3.6 million in tax adjustments primarily related to non-deductible items, partially offset by the loss incurred in 2014 from the extinguishment of debt associated with the debt refinancings completed in conjunction with the Spin-Off.

Discontinued Operations. Net income from discontinued operations in 2015 was $0.2 million compared to $51.8 million for 2014. There were no revenues reported within discontinued operations during 2015 compared to $404.2 million for 2014 due to the Spin-Off on May 30, 2014. Operating income included within discontinued operations was $0.4 million and $81.1 million for 2015 and 2014, respectively. The decreases in revenue and operating income year-over-year primarily relate to the absence of accommodations operations in 2015 compared to five months of operations in 2014.

Other Comprehensive Income (Loss). Other comprehensive income (loss) decreased from income of less than $0.1 million in 2014 to a loss of $28.6 million in 2015 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, 2015, currency translation adjustments recognized as a component of other comprehensive loss were primarily attributable to the United Kingdom, Brazil and Canada. As of December 31, 2015, the exchange rates of the British pound, the Brazilian real and the Canadian dollar compared to the U.S. dollar weakened by 5%, 31% and 16%, respectively, compared to the exchange rates at December 31, 2014.

Our primary liquidity needs are to fund operating and capital expenditures, which in the past have included expanding and upgrading our Offshore Products manufacturing facilities and equipment, replacing and increasing Completion Services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt, fund our stock repurchase program and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our credit facilities and capital market transactions. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our revolving credit facility.

Despite the continued weak market conditions, cash totaling $149.3 million was provided by continuing operations during the year ended December 31, 2016 compared to cash totaling $255.8 million provided by continuing operations during the year ended December 31, 2015. During 2016 and 2015, $90.3 million and $78.2 million, respectively was provided from net working capital reductions, primarily due to decreases in receivables and inventories, partially offset by decreases in accounts payable and accrued liabilities.

A total of $29.3 million in cash was used in investing activities during the year ended December 31, 2016, compared to $147.2 million used during the year ended December 31, 2015. Capital expenditures totaled $29.7 million and $114.7 million during the years ended December 31, 2016 and 2015, respectively. Capital expenditures in both years consisted principally of purchases of Completion Services equipment, expansion and upgrading of our Offshore Products segment facilities and various other capital spending initiatives.

On January 2, 2015, we acquired all of the equity of MMC. Total transaction consideration was $33.4 million, net of cash acquired, funded from amounts available under the Company’s revolving credit facility.

We currently expect to invest a total of approximately $40 million to $45 million for capital expenditures during 2017 to upgrade and maintain our Offshore Products facilities and equipment, to replace and upgrade our Completion Services equipment and to fund various other capital spending projects. Whether planned expenditures will actually be spent in 2017 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 revolving credit facility. The foregoing capital expenditure expectations do not include any funds that might be spent on 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, 2016, we had cash totaling $68.8 million, of which $67.7 million was held by our international subsidiaries, primarily in Singapore, Canada and the United Kingdom. Our intent is to utilize at least a portion of these cash balances for future investment outside the United States. Approximately $34 million of cash held by our international subsidiaries can be repatriated without triggering any incremental tax consequences. During 2016, we repatriated $20.1 million from our international subsidiaries which was used to reduce outstanding borrowings under our revolving credit facility.

Net cash of $84.9 million was used in financing activities during the year ended December 31, 2016, primarily attributable to the repayment of $80.7 million in borrowings under our revolving credit facility. Net cash of $124.7 million was used in financing activities during the year ended December 31, 2015, primarily associated with repurchases of our common stock totaling $105.9 million.

We believe that cash on hand, cash flow from operations and available borrowings under our 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 position, and the issuance of additional equity securities could result in significant dilution to stockholders.

Stock Repurchase Program. 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 was scheduled to expire on July 29, 2016. On July 27, 2016, our Board of Directors extended the share repurchase program for one year to July 29, 2017. No shares of our common stock were repurchased under the program in 2016. During 2015, a total of $105.9 million of our stock (2,674,218 shares) were repurchased under these programs compared to $218.9 million (2,843,142 shares) during 2014. The amount remaining under our current share repurchase authorization as of December 31, 2016 was $136.8 million. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate.

Credit Facilities. The Company has a $600 million senior secured revolving credit facility (the revolving credit facility) with an option to increase the maximum borrowings under its facility to $750 million contingent upon additional lender commitments prior to its maturity on May 28, 2019. As of December 31, 2016, we had $42.2 million in borrowings outstanding under the Credit Agreement and $30.7 million of outstanding letters of credit, leaving $153.1 million available to be drawn under the revolving credit facility. The total amount available to be drawn under our revolving credit facility was less than the lender commitments as of December 31, 2016, due to the maximum leverage ratio covenant in our revolving credit facility which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant in 2017 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).

The revolving credit facility is governed by a 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. On October 3, 2016, the Company amended the revolving credit facility to, among other things, allow for certain intercompany transactions between or among the Company and its subsidiaries (which may have otherwise been considered investments not permitted under the Credit Agreement) and make certain other technical changes and modifications. Amounts outstanding under the revolving credit facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio of the Company’s total leverage to EBITDA. We must also pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% during 2016. During 2016, our applicable margin over LIBOR was 1.50%. Interest expense as a percentage of total debt outstanding increased from 3.6% in 2015 to 6.5% in 2016. The increase in the weighted average interest rate was attributable to an increased proportion of interest expense associated with unused commitment fees coupled with lower average borrowings outstanding under our revolving credit facility.

The 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 and a maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of December 31, 2016, we were in compliance with our debt covenants and expect to continue to be in compliance throughout 2017. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries.

Under the Company's 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.

Our total debt represented 3.7% of our combined total debt and stockholders’ equity at December 31, 2016 compared to 9.1% at December 31, 2015.

Contractual Obligations. The following summarizes our contractual obligations at December 31, 2016, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):

Our debt obligations at December 31, 2016 are included in our consolidated balance sheet, which is a part of our Consolidated Financial Statements included in this Annual Report on Form 10-K. We have not entered into any material leases subsequent to December 31, 2016.

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

As of December 31, 2016, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

Our primary deferred tax assets at December 31, 2016, are related to foreign tax credit carryforwards, net operating loss carryforwards, employee benefits (stock-based compensation) and inventory allowance for obsolescence. Further information with respect to expiration periods of our foreign tax credit and net operating loss carryforwards is included in Note 13 to Consolidated Financial Statements included in this Annual Report on Form 10-K. .

The Company’s income tax benefit for 2016 totaled $26.9 million, or 36.7% of pretax loss, compared to income tax expense of $22.2 million, or 43.9% of pretax income, for 2015. The decrease in the effective tax rate from the prior year was largely the result of the impact in 2015 of a $4.1 million valuation allowance recorded against the Company’s tax loss carryforwards in various foreign jurisdictions, and $3.6 million in tax adjustments primarily related to non-deductible items.

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

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

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on their fair value or our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, insurance claims, warranty claims, contractual claims and obligations and discontinued operations.

Our goodwill totaled $263.4 million, or 19%, of our total assets, as of December 31, 2016. Our other intangible assets totaled $52.7 million, or 4%, of our total assets, as of December 31, 2016. The assessment of impairment of long-lived assets, including intangibles, is conducted whenever changes in the facts and circumstances indicate a loss in value may have occurred. Indicators of impairment might include persistent negative economic trends affecting the markets we serve, recurring losses or lowered expectations of future cash flows expected to be generated by our assets. The determination of the amount of impairment would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether a decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment losses. Based on the Company's December 2016 review, the carrying values of its asset groups are recoverable, and no impairment losses were recorded. However, a prolonged continuation of the current industry downturn may result in changes in our estimates of projected operating cash flows and could potentially cause us to impair the values of our long-lived assets, including finite-lived intangible assets. At December 31, 2016, long-lived assets and finite-lived intangibles assets totaled approximately $553 million and $53 million, respectively.

We evaluate each reporting unit at least annually or on an interim basis, if an indicator of goodwill impairment was determined to occur, as defined in current accounting standards. Our reporting units include Completion Services, Drilling Services and Offshore Products. There is no remaining goodwill in our Drilling Services reporting unit. As part of the goodwill impairment analysis, current accounting standards give us the option to first perform a qualitative assessment to determine whether it is more likely than not (that is, a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2016, we performed the two-step impairment test given the impact of low crude oil prices on our operating results. In performing the two-step impairment test, we estimate the implied fair value (“IFV”) of each reporting unit and compare the IFV to the carrying value of such unit. Because none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process (a Level 3 fair value measurement). In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilize, depending on circumstances, a combination of trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is primarily affected by future oil and natural gas prices, anticipated spending by our customers, and the cost of capital. As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV's of all of our reporting units to assess the reasonableness of the IFV's in the aggregate. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis is conducted to determine the amount of impairment, if any. At the date of our goodwill impairment test in 2016, the IFV of our Offshore Products and Completion Services reporting units each substantially exceeded their carrying values. As of December 31, 2016, our market capitalization was $2.0 billion as compared to the carrying value of our equity of $1.2 billion. A prolonged continuation of the current industry downturn may result in changes in our estimates of forward cash flow timing and amounts, as well as comparable trading multiples, and may result in goodwill impairment losses.

Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post-delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date compared to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Costs incurred and estimated profits in excess of billings on percentage-of-completion contracts are recognized as unbilled receivables. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings. In our Well Site Services segment, revenues are recognized based on a periodic (usually daily) rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets after considering the write-off of the remaining net book value of the equipment. For Drilling Services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.

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

The determination of the collectability of amounts due from customer accounts requires the Company to make judgments regarding future events and trends. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer basis taking into account current market conditions and trends. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers. A substantial portion of the Company’s revenues come from international oil companies, international oilfield service companies, and government-owned or government-controlled oil companies. If worldwide oil and gas drilling activity were to continue to decline, the creditworthiness of the Company’s customers could deteriorate and they may be unable to pay their receivables, requiring additional allowances to be recorded. At December 31, 2016 and 2015, our allowance for bad debts totaled $8.5 million and $6.9 million, or 3.5% and 2.0% of gross accounts receivable, respectively. Historically, the Company’s charge-offs and provisions for the allowance for doubtful accounts in any given year have been immaterial to the Company’s consolidated financial statements.

Inventory is carried at the lower of cost or estimated net realizable value. The Company determines reserves for inventory based on historical usage of inventory on-hand, assumptions about future demand and market conditions, and estimates about potential alternative uses, which are usually limited. The Company’s inventory consists of specialized spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s large installed base of specialized equipment used throughout the oilfield. Customers rely on the Company to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The Company’s estimated carrying value of inventory therefore depends upon demand driven by oil and gas drilling and well remediation activity, which depends in turn upon oil and gas prices, the general outlook for economic growth worldwide, available financing for the Company’s customers, political stability in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. At December 31, 2016 and 2015, inventory reserves totaled $14.8 million and $12.9 million, or 7.8% and 5.7% of gross inventory, respectively.

The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Our judgment in this area is influenced by our historical experience in operating our assets, technological developments and expectations of future demand for the assets. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

We estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (the “Plan”) on their respective dates of grant. An estimate of the fair value of each stock option or restricted stock award determines the amount of stock compensation expense that we will recognize in the future. We use the Black-Scholes-Merton “closed form” model to value stock options awarded under the Plan. The fair value of service-based and performance-based restricted stock awarded under the Plan is determined by the quoted market price of the Company’s common stock on the date of grant, except for a limited number of performance-based restricted awards which are valued using a Monte Carlo simulation model as a result of the inclusion of performance metrics that are not based solely on the performance of our Company’s common stock.

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

When the Company's earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries. During 2016 and 2015, we repatriated $20.1 million and $35.2 million, respectively, from our international subsidiaries which was used to reduce outstanding borrowings under our revolving credit facility.

The Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. This assessment requires analysis of available positive and negative evidence, including losses in recent years, reversals of temporary differences, forecasts of future income, assessment of future business assumptions and tax planning strategies. During 2015 and 2016, we recorded valuation allowances primarily with respect to net operating loss carryforwards of certain of our operations outside the United States. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to our forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

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

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

In May 2014, the FASB issued guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to receive in exchange for those goods or services. The guidance permits the use of either a retrospective or modified retrospective transition method. The Company will adopt this guidance on January 1, 2018, and currently anticipates using the modified retrospective transition method. We continue to review our contracts with certain customers within our Offshore Products segment to determine the impact of the standard on such contracts and on our consolidated financial statements.

In February 2016, the FASB issued guidance on leases which introduces the recognition of lease assets and lease liabilities by lessees for all leases which are not short-term in nature. The new standard requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. The Company will adopt this guidance on January 1, 2019. Upon initial evaluation, we believe the key change upon adoption will be the balance sheet recognition of our leases. The income statement recognition appears similar to our current methodology. The Company’s future obligations under operating leases as of December 31, 2016 are summarized in Note 14, “Commitments and Contingencies.”

In March 2016, the FASB issued guidance on employee share-based payment accounting which modifies existing guidance related to the accounting for forfeitures, employer tax withholding on stock-based compensation and the financial statement presentation of excess tax benefits or deficiencies. The Company adopted this guidance on January 1, 2017 and does not expect it to have a material impact on its consolidated financial statements.

In January 2017, the FASB issued guidance which simplifies the test of goodwill impairment. Under the revised standard, the Company will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. The revised guidance requires a prospective transition and permits early adoption for interim and annual goodwill impairment tests performed after January 1, 2017. The Company adopted this standard effective January 1, 2017. See Note 9, "Goodwill and Other Intangible Assets."

In April 2015, the FASB issued guidance on the presentation of debt issuance costs which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company adopted this new guidance effective January 1, 2016 resulting in the reclassification of deferred financing costs associated with its revolving credit agreement from other noncurrent assets to a reduction of long-term debt on a retrospective basis. The Company’s consolidated balance sheet included deferred financing costs of $2.7 million as of December 31, 2015 that were reclassified from other noncurrent assets to long-term debt. As of December 31, 2016, $2.0 million of deferred financing costs were included as a reduction of long-term debt in the consolidated balance sheet. See Note 10, “Long-term Debt.”

Market risk refers to the potential for losses arising from changes in interest rates, foreign currency fluctuations and exchange rates, equity prices and commodity prices including the correlation among these factors and their volatility.

Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates. We enter into derivative instruments only to the extent considered necessary to meet risk management objectives and do not use derivative contracts for speculative purposes.

Interest Rate Risk. We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of December 31, 2016, we had floating-rate obligations totaling $42.2 million drawn under our credit facility. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rates increased by 1% from December 31, 2016 levels, our consolidated interest expense would increase by a total of approximately $0.4 million annually.

Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S. (primarily in our Offshore Products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During 2016, our reported foreign exchange gains were $4.7 million and are included in “Other operating (income) expense, net” in the Consolidated Statements of Operations. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into foreign exchange agreements with financial institutions. As of December 31, 2016 and 2015, we had outstanding foreign currency forward purchase contracts with notional amounts of $2.2 million and $5.4 million, respectively, related to expected cash flows denominated in Euros. As a result of these currency contracts becoming ineffective in 2015, we recorded $0.4 million of foreign exchange loss related to amounts reclassified from accumulated other comprehensive loss into an expense on the statement operations in 2015.

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, increased from $50.7 million at December 31, 2015 to $70.3 million at December 31, 2016, primarily as a result of foreign currency exchange rate differences in the current year of $19.8 million. This other comprehensive loss is 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. As of December 31, 2016, the exchange rate of the British pound compared to the U.S. dollar weakened by 16% compared to the exchange rate at December 31, 2015, while the exchange rates of the Brazilian real and Canadian dollar compared to the U.S. dollar strengthened by 22% and 3%, respectively, during the same period. As of December 31, 2015, the exchange rates of the British pound, the Brazilian real and the Canadian dollar compared to the U.S. dollar weakened by 5%, 31% and 16%, respectively, compared to the exchange rates at December 31, 2014.

Our Consolidated Financial Statements and supplementary data of the Company begin on page 57 of this Annual Report on Form 10-K and are incorporated by reference into this Item 8. Selected quarterly financial data is set forth in Note 18 to our Consolidated Financial Statements, which is incorporated herein by reference.

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

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

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 at the reasonable assurance level.

Pursuant to section 906 of The Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Commission. These certifications accompanied this report when filed with the Commission, but are not set forth herein.

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

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

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

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2016 was conducted. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control–Integrated Framework (2013 Framework). Based on our assessment we believe that, as of December 31, 2016, the Company's internal control over financial reporting is effective based on those criteria.

The attestation report of Ernst & Young LLP, the Company's independent registered public accounting firm, on the Company's internal control over financial reporting is set forth in this Annual Report on Form 10-K on page 59 and is incorporated herein by reference.

During the Company's fourth fiscal quarter ended December 31, 2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2016 that was not reported on a Form 8-K during such time.

The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders.

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

The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders.

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

The information required by Item 13 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders.

Information concerning principal accounting fees and services and the audit committee's preapproval policies and procedures appear in the Company's Definitive Proxy Statement for the 2017 Annual Meeting of Stockholders under the heading "Fees Paid to Ernst & Young LLP" and is incorporated herein by reference.

(1) Financial Statements: Reference is made to the index set forth on page 57 of this Annual Report on Form 10-K.

(2) Financial Statement Schedules: No schedules have been included herein because the information required to be submitted has been included in the Consolidated Financial Statements or the Notes thereto, or the required information is inapplicable.

(3) Index of Exhibits: See Index of Exhibits, below, for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Annual Report on Form 10-K by Item 601 of Regulation S-K.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 17, 2017.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 17, 2017.

We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oil States International, Inc. and subsidiaries at December 31, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2017 expressed an unqualified opinion thereon.

We have audited Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Oil States International, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s annual report on internal control over financial reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

In our opinion, Oil States International, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016 and our report dated February 17, 2017 expressed an unqualified opinion thereon.

	Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Treasury Stock			Noncontrolling Interest			Total Stockholders' Equity
Balance, December 31, 2013	$	592	$	637,438		$	2,320,453		$	(85,675	)	$	(249,391	)	$	1,877		$	2,625,294
Net income		–		–			179,003			–			–			–			179,003
Net income from noncontrolling interest – discontinued operations		–		–			–			–			–			566			566
Currency translation adjustment		–		–			–			235			–			(24	)		211
Other comprehensive income		–		–			–			(185	)		–			–			(185	)
Unrealized gain on forward contracts, net of tax		–		–			–			6			–			–			6
Stock-based compensation expense:
Restricted stock		–		23,513			–			–			–			–			23,513
Stock options		–		3,636			–			–			–			–			3,636
Exercise/vesting of stock-based awards, including tax impact		4		17,124			–			–			–			–			17,128
Surrender of stock to pay taxes on restricted stock awards		–		–			–			–			(6,136	)		–			(6,136	)
Exercise of stock options/stock awards released – discontinued operations		–		2,727			–			–			–			–			2,727
OIS common stock withdrawn from deferred compensation plan		–		1,234			–			–			82			–			1,316
Spin-Off of Civeo		–		(242	)		(1,348,190	)		63,519			–			(1,764	)		(1,286,677	)
Dividends paid (noncontrolling interest)		–		–			–			–			–			(489	)		(489	)
Acquisition of non-controlling interest		–		(184	)		–			–			–			(166	)		(350	)
Stock repurchases		–		–			–			–			(218,906	)		–			(218,906	)
Other		14		(14	)		–			–			–			–			–
Balance, December 31, 2014		610		685,232			1,151,266			(22,100	)		(474,351	)		–			1,340,657
Net income		–		–			28,597			–			–			–			28,597
Currency translation adjustment (excluding intercompany advances)		–		–			–			(24,191	)		–			–			(24,191	)
Currency translation adjustment on intercompany advances		–		–			–			(3,766	)		–			–			(3,766	)
Other comprehensive income		–		–			–			(948	)		–			–			(948	)
Unrealized gain on forward contracts, net of tax		–		–			–			307			–			–			307
Stock-based compensation expense:
Restricted stock		4		18,832			–			–			–			–			18,836
Stock options		–		2,942			–			–			–			–			2,942
Exercise/vesting of stock-based awards, including tax impact		3		5,977			–			–			–			–			5,980
Surrender of stock to pay taxes on stock option exercises and restricted stock awards		–		–			–			–			(6,826	)		–			(6,826	)
Stock repurchases		–		–			–			–			(105,916	)		–			(105,916	)
OIS common stock withdrawn from deferred compensation plan		–		(3	)		–			–			3			–			–
Balance, December 31, 2015		617		712,980			1,179,863			(50,698	)		(587,090	)		–			1,255,672
Net loss		–		–			(46,390	)		–			–			–			(46,390	)
Currency translation adjustment (excluding intercompany advances)		–		–			–			(23,802	)		–			–			(23,802	)
Currency translation adjustment on intercompany advances		–		–			–			4,024			–			–			4,024
Other comprehensive income		–		–			–			176			–			–			176
Stock-based compensation expense:
Restricted stock		6		18,899			–			–			–			–			18,905
Stock options		–		2,245			–			–			–			–			2,245
Exercise/vesting of stock-based awards, including tax impact		–		(2,609	)		–			–			–			–			(2,609	)
Surrender of stock to pay taxes on restricted stock awards				–			–			–			(3,980	)		–			(3,980	)
OIS common stock withdrawn from deferred compensation plan		–		47			–			–			19			–			66
Balance, December 31, 2016	$	623	$	731,562		$	1,133,473		$	(70,300	)	$	(591,051	)	$	–		$	1,204,307

	Year Ended December 31,
	2016			2015			2014
Cash flows from operating activities:
Net income (loss)	$	(46,390	)	$	28,597		$	179,003
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Income (loss) from discontinued operations		4			(226	)		(51,776	)
Depreciation and amortization		118,720			131,257			124,776
Stock-based compensation expense		21,322			21,778			25,581
Deferred income tax benefit		(37,606	)		(3,173	)		(11,970	)
Tax impact of stock-based payment arrangements		–			(469	)		(6,904	)
Gains on disposals of assets		(802	)		(1,274	)		(2,043	)
Amortization of deferred financing costs		785			780			1,819
Loss on extinguishment of debt		–			–			100,380
Other, net		2,923			283			3,127
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		85,503			156,945			(65,787	)
Inventories		32,158			17,777			1,430
Accounts payable and accrued liabilities		(27,716	)		(98,354	)		5,741
Income taxes payable		(1,930	)		4,897			(15,130	)
Other operating assets and liabilities, net		2,286			(3,050	)		14,397
Net cash flows provided by continuing operating activities		149,257			255,768			302,644
Net cash flows provided by discontinued operating activities		–			353			135,392
Net cash flows provided by operating activities		149,257			256,121			438,036
Cash flows from investing activities:
Capital expenditures		(29,689	)		(114,738	)		(199,256	)
Acquisitions of businesses, net of cash acquired		–			(33,427	)		(157	)
Proceeds from disposition of property, plant and equipment		1,532			2,655			3,535
Other, net		(1,135	)		(1,686	)		(2,626	)
Net cash flows used in continuing investing activities		(29,292	)		(147,196	)		(198,504	)
Net cash flows used in discontinued investing activities		–			–			(119,199	)
Net cash flows used in investing activities		(29,292	)		(147,196	)		(317,703	)
Cash flows from financing activities:
Revolving credit facility (repayments) borrowings, net		(80,674	)		(17,825	)		140,684
Repayment of 6 1/2% Senior Notes		–			–			(630,307	)
Repayment of 5 1/8% Senior Notes		–			–			(419,794	)
Debt and capital lease repayments		(534	)		(541	)		(538	)
Payment of financing costs		(72	)		(2	)		(3,897	)
Distribution received from Spin-Off of Civeo		–			–			750,000
Issuance of common stock from stock-based payment arrangements		367			5,920			10,475
Purchase of treasury stock		–			(105,916	)		(226,303	)
Tax impact of stock-based payment arrangements		–			469			6,904
Shares added to treasury stock as a result of net share settlements due to vesting of restricted stock		(3,962	)		(6,827	)		(6,136	)
Net cash flows used in continuing financing activities		(84,875	)		(124,722	)		(378,912	)
Net cash flows used in discontinued financing activities		–			–			(282,204	)
Net cash flows used in financing activities		(84,875	)		(124,722	)		(661,116	)
Effect of exchange rate changes on cash		(2,263	)		(1,493	)		(5,260	)
Net change in cash and cash equivalents		32,827			(17,290	)		(546,043	)
Cash and cash equivalents, beginning of year		35,973			53,263			599,306

Cash and cash equivalents, end of year	$	68,800		$	35,973		$	53,263

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

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

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, bank debt and foreign currency forward contracts. The Company believes that the carrying values of these instruments on the accompanying consolidated balance sheets approximate their fair values.

Inventories

Inventories consist of oilfield products, manufactured equipment, spare parts for manufactured equipment, and work-in-process. Inventories also include raw materials, labor, subcontractor charges, manufacturing overhead and other supplies and are carried at the lower of cost or market. The cost of inventories is determined on an average cost or specific-identification method. A reserve for excess, damaged and/or obsolete inventory is maintained based on the age, turnover or condition of the inventory.

Property, Plant, and Equipment

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

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(continued)

Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price paid for acquired businesses over the allocated fair value of the related net assets after impairments, if applicable. We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. Our reporting units with goodwill as of December 31, 2016 include Offshore Products and Completion Services. As part of the goodwill impairment analysis, current accounting standards give us the option to first perform a qualitative assessment to determine whether it is more likely than not (that is, a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2016, we performed the two-step impairment test given the impact of low oil prices on our operating results. In performing the two-step impairment test, we estimate the implied fair value (“IFV”) of each reporting unit and compare the IFV to the carrying value of such unit. We utilize, depending on circumstances, a combination of trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. We discount our projected cash flows using a long-term weighted average cost of capital for each reporting unit based on our estimate of investment returns that would be required by a market participant. As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV's of all of our reporting units to assess the reasonableness of the IFV's in the aggregate. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any. In 2014, 2015 and 2016, our goodwill impairment tests indicated that the fair value of each of our reporting units is greater than its carrying amount.

For other intangible assets that we amortize, we review the useful life of the intangible asset and evaluate each reporting period whether events and circumstances warrant a revision to the remaining useful life. Based on the Company’s review, the carrying values of its other intangible assets are recoverable, and no impairment losses have been recorded for the periods presented.

See Note 9 – Goodwill and Other Intangible Assets.

Impairment of Long-Lived Assets

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

Foreign Currency and Other Comprehensive Loss

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(continued)

Currency Exchange Rate Risk

A portion of revenues, earnings and net investments in operations outside the United States are exposed to changes in currency exchange rates. We seek to manage our currency exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into currency exchange agreements with financial institutions. As of December 31, 2016 and 2015, we had outstanding foreign currency forward purchase contracts with notional amounts of $2.2 million and $5.4 million, respectively, related to expected cash flows denominated in Euros. As a result of these currency contracts becoming ineffective in 2015, we recorded $0.4 million of currency exchange losses related to amounts reclassified from accumulated other comprehensive loss into an expense on the statement of operations in 2015. Currency exchange gains and losses have totaled gains of $4.7 million and $3.7 million in 2016 and 2015, respectively, and losses of $0.4 million in 2014, and were included in “Other operating (income) expense.”

Revenue and Cost Recognition

Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post-delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date compared to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Costs incurred and estimated profits in excess of billings on percentage-of-completion contracts are recognized as unbilled receivables. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Factors that may affect future project costs and margins include weather, production efficiencies, availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings. In our Well Site Services segment, revenues are recognized based on a periodic (usually daily) rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets after considering the write-off of the remaining net book value of the equipment. For Drilling Services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.

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

Income Taxes

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(continued)

When the Company's earnings from international subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries. During 2016 and 2015, we repatriated $20.1 and $35.2 million, respectively, from our international subsidiaries which was used to reduce outstanding borrowings under our revolving credit facility.

The Company records a valuation allowance in the reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. This assessment requires analysis of available positive and negative evidence, including losses in recent years, reversals of temporary differences, forecasts of future income, assessment of future business assumptions and tax planning strategies. During 2015 and 2016, we recorded valuation allowances primarily with respect to net operating loss carryforwards of certain of our operations outside the United States. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to our forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

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

Discontinued Operations

The operating results of a component of our business that either has been disposed of or is classified as held for sale are presented as discontinued operations when both of the following conditions are met: (a) the operations and cash flows of the component have been or will be eliminated from our ongoing operations as a result of the disposal transaction and (b) we will not have any significant continuing involvement in the operations of the disposed component. We consider a component of our business to be one that comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the balance of our business. No components of our business have been disposed of or classified as held for sale subsequent to 2014.

Receivables and Concentration of Credit Risk

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

Allowances for Doubtful Accounts

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

Earnings per Share

Diluted earnings per share (“EPS”) amounts include the effect of the Company's outstanding stock options and restricted stock shares under the treasury stock method. We have shares of restricted stock issued and outstanding, which remain subject to vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common stockholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share amounts under the two class method in periods in which we have earnings from continuing operations.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(continued)

The presentation of basic EPS amounts on the face of the accompanying consolidated statements of operations is computed by dividing the net income (loss) applicable to the Company’s common stockholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any.

Stock-Based Compensation

The fair value of share-based payments is estimated using the quoted market price of the Company’s stock and pricing models as of the date of grant as further discussed in Note 15. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. In addition to service-based awards, in 2016, 2015 and 2014, the Company issued performance-based awards which are conditional based upon performance and may vest in an amount that will depend on the Company’s achievement of specified performance objectives.

Guarantees

Some product sales in our Offshore Products businesses are sold with a warranty, generally ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are estimated based upon historical experience by product, configuration and geographic region. Our total liability related to estimated warranties was $1.1 million and $2.6 million as of December 31, 2016 and 2015, respectively.

During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2016, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements (letters of credit) was $36.1 million. The Company has not recorded any liability in connection with these guarantee arrangements. The Company does not believe, based on historical experience and information currently available, that it is likely that any amounts will be required to be paid under these guarantee arrangements.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Examples of a few such estimates include revenue and income recognized on the percentage-of-completion method, any valuation allowance recorded on net deferred tax assets, warranty, reserves on inventory and allowance for doubtful accounts and potential future adjustments related to contractual agreements. Actual results could materially differ from those estimates.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(continued)

Accounting for Contingencies

9. Goodwill and Other Intangible Assets

The Company tests for impairment using a fair value approach, at the "reporting unit" level. A reporting unit is the operating segment, or a business one level below that operating segment (the "component" level) if discrete financial information is prepared and regularly reviewed by management at the component level. The Company had two reporting units, Offshore Products and Completion Services, with goodwill as of December 31, 2016. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company recognizes an impairment loss for any amount by which the carrying amount of a reporting unit's goodwill exceeds the reporting unit's IFV of goodwill. If our initial qualitative assessment of potential goodwill impairment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company uses, as appropriate in the current circumstance, comparative market multiples, discounted cash flow calculations and acquisition comparables to establish the reporting unit's fair value (a Level 3 fair value measurement).

The Company amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are reviewed for impairment if there are indicators of impairment based on undiscounted cash flows and, if impaired, written down to fair value based on either discounted cash flows or appraised values. As of December 31, 2016 and 2015, no provision for impairment of other intangible assets was required.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Changes in the carrying amount of goodwill for the years ended December 31, 2016 and 2015 are as follows (in thousands):

	Well Site Services
	Completion Services			Drilling Services			Subtotal			Offshore Products			Total
Balance as of December 31, 2014
Goodwill	$	200,967		$	22,767		$	223,734		$	145,762		$	369,496
Accumulated impairment losses		(94,528	)		(22,767	)		(117,295	)		–			(117,295	)
		106,439			–			106,439			145,762			252,201
Goodwill acquired and purchase price adjustments		–			–			–			13,943			13,943
Foreign currency translation and other changes		(2,064	)		–			(2,064	)		(293	)		(2,357	)
Balance as of December 31, 2015	$	104,375		$	–		$	104,375		$	159,412		$	263,787

Balance as of December 31, 2015
Goodwill	$	198,903		$	22,767		$	221,670		$	159,412		$	381,082
Accumulated impairment losses		(94,528	)		(22,767	)		(117,295	)		–			(117,295	)
		104,375			–			104,375			159,412			263,787
Foreign currency translation and other changes		375			–			375			(793	)		(418	)
Balance as of December 31, 2016	$	104,750		$	–		$	104,750		$	158,619		$	263,369

Balance as of December 31, 2016
Goodwill	$	199,278		$	22,767		$	222,045		$	158,619		$	380,664
Accumulated impairment losses		(94,528	)		(22,767	)		(117,295	)		–			(117,295	)
	$	104,750		$	–		$	104,750		$	158,619		$	263,369

The following table presents the total gross carrying amount of intangibles and the total accumulated amortization for major intangible asset classes as of December 31, 2016 and 2015 (in thousands):

	As of December 31,
	2016				2015
Other Intangible Assets	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	44,557	$	19,225	$	44,557	$	15,790
Contracts/Agreements/Backlog		1,064		709		1,064		355
Patents		20,056		8,418		20,024		6,521
Technology		10,111		4,064		10,111		3,052
Noncompete agreements		4,358		2,216		4,358		1,565
Trademarks and other		9,737		2,505		8,237		1,683
Total other intangible assets	$	89,883	$	37,137	$	88,351	$	28,966

The weighted average remaining amortization period for all intangible assets, other than goodwill, was 8.2 years as of December 31, 2016 and 8.7 years as of December 31, 2015. Total amortization expense is expected to be $8.1 million in 2017, $7.4 million in 2018, $7.2 million in 2019, $7.0 million in 2020 and $6.0 million in 2021. Amortization expense was $8.2 million, $7.8 million and $7.0 million in the years ended December 31, 2016, 2015 and 2014, respectively.

10. Long-term Debt

As of December 31, 2016 and 2015, long-term debt consisted of the following (in thousands):

	2016		2015
Revolving credit facility ⁽¹⁾	$	40,230	$	120,191

Capital lease obligations and other debt		5,696		6,229
Total debt		45,926		126,420
Less: Current portion		538		533
Total long-term debt and capitalized leases	$	45,388	$	125,887

(1)

Amounts presented are net of $2.0 million and $2.7 million, respectively, of unamortized debt issuance costs.

Scheduled maturities of combined long-term debt as of December 31, 2016, are as follows (in thousands):

2017	$	538
2018		449
2019		40,572
2020		359
2021		374
Thereafter		3,634
	$	45,926

The Company's capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $1.1 million and $0.8 million, respectively, at December 31, 2016. The value of capitalized leases and the related accumulated depreciation totaled $1.5 million and $0.9 million, respectively, at December 31, 2015.

Credit Facility

The Company has a $600 million senior secured revolving credit facility (the revolving credit facility) with an option to increase the maximum borrowings under its revolving credit facility to $750 million subject to additional lender commitments prior to its maturity on May 28, 2019. As of December 31, 2016, we had $42.2 million outstanding under the Credit Agreement and an additional $30.7 million of outstanding letters of credit, leaving $153.1 million available to be drawn under the revolving credit facility. The total amount available to be drawn under our revolving credit facility was less than the lender commitments as of December 31, 2016, due to the maximum leverage ratio covenant in our revolving credit facility which serves to limit borrowings. We expect our availability to continue to be limited by the maximum leverage ratio covenant in 2017 based upon our forecast of our trailing twelve-month EBITDA (as defined in the Credit Agreement and further discussed below).

The revolving credit facility is governed by a 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, and Royal Bank of Canada, as Syndication agent, and Compass Bank, as Documentation agent. On October 3, 2016, the Company amended the revolving credit facility to, among other things, allow for certain intercompany transactions between or among the Company and its subsidiaries (which may have otherwise been considered investments not permitted under the Credit Agreement) and make certain other technical changes and modifications. Amounts outstanding under the revolving credit facility bear interest at LIBOR plus a margin of 1.50% to 2.50%, or at a base rate plus a margin of 0.50% to 1.50%, in each case based on a ratio of the Company’s total leverage to EBITDA. During the year ended December 31, 2016, our applicable margin over LIBOR was 1.50%. We must also pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. The unused commitment fee was 0.375% for the year ended December 31, 2016. The 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 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill impairments, losses on extinguishment of debt, debt discount amortization, and other non-cash charges. As of December 31, 2016, we were in compliance with our debt covenants.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our domestic subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant domestic subsidiaries. The revolving credit facility also contains negative covenants that limit the Company's ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.

Loss on Extinguishment of Debt

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 completed in connection with the Spin-Off in the second quarter, which resulted in a loss of $96.7 million consisting of the premium paid over book value for the Notes and the write-off of unamortized deferred financing costs associated with such notes. The premium paid to repurchase the 6 1/2% and 5 1/8% Notes was due to their fair market value exceeding their book value at the date tendered or redeemed. In addition, as a result of the refinancing of our existing credit facility in 2014, we recognized a loss on extinguishment of $3.7 million (net of $1.8 million allocated to discontinued operations for the Canadian portion of the facility) from the write-off of unamortized deferred financing costs.

13. Income Taxes

Consolidated income (loss) from continuing operations before income taxes for the years ended December 31, 2016, 2015 and 2014 consisted of the following (in thousands):

	2016			2015			2014
United States	$	(113,512	)	$	(21,598	)	$	128,639
Foreign		40,187			72,166			67,705
Total	$	(73,325	)	$	50,568		$	196,344

The components of the income tax provision (benefit) with respect to income (loss) from continuing operations for the years ended December 31, 2016, 2015 and 2014 consisted of the following (in thousands):

	2016			2015			2014
Current:
Federal	$	(534	)	$	7,221		$	56,317
State		1,053			1,868			5,426
Foreign		10,148			16,281			19,344
		10,667			25,370			81,087
Deferred:
Federal		(34,816	)		(5,656	)		(8,620	)
State		(2,807	)		(496	)		26
Foreign		17			2,979			(3,376	)
		(37,606	)		(3,173	)		(11,970	)
Total provision (benefit)	$	(26,939	)	$	22,197		$	69,117

A reconciliation of the federal statutory tax provision (benefit) rate to the effective tax provision (benefit) rate for the years ended December 31, 2016, 2015 and 2014 is as follows:

	2016			2015			2014
United States statutory tax provision (benefit) rate		(35.0	)%		35.0	%		35.0	%
Effect of foreign income taxed at different rates		(4.3	)		(11.1	)		(2.8	)
Valuation allowance against tax assets		3.1			8.1			–
Non-deductible compensation		1.1			7.6			0.3
Other non-deductible expenses		2.0			4.5			1.4
Domestic manufacturing deduction		–			(2.6	)		(1.9	)
State income taxes, net of federal benefits		(2.1	)		1.3			2.8
Other, net		(1.5	)		1.1			0.4
Effective tax provision (benefit) rate		(36.7	)%		43.9	%		35.2	%

The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2016 and 2015 are as follows (in thousands):

	2016			2015
Deferred tax assets:
Foreign tax credit carryover	$	32,548		$	24,852
Net operating loss carryforwards		21,871			4,580
Employee benefits		18,060			18,252
Inventory reserves		7,152			7,394
Other reserves		2,939			3,580
Allowance for doubtful accounts		2,445			1,657
Other		668			635
Gross deferred tax asset		85,683			60,950
Valuation allowance		(7,033	)		(3,970	)
Net deferred tax asset		78,650			56,980
Deferred tax liabilities:
Tax over book depreciation		(62,403	)		(77,632	)
Intangible assets		(19,878	)		(17,804	)
Accrued liabilities		(1,016	)		(1,513	)
Deferred revenue		(268	)		(113	)
Other		–			(377	)
Deferred tax liability		(83,565	)		(97,439	)
Net deferred tax liability	$	(4,915	)	$	(40,459	)

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	2016			2015
Balance sheet classification:
Other non-current assets	$	121		$	38
Deferred tax liability		(5,036	)		(40,497	)
Net deferred tax liability	$	(4,915	)	$	(40,459	)

Our primary deferred tax assets at December 31, 2016, were related to foreign tax credit carryforwards, net operating loss carryforwards, employee benefits (stock-based compensation) and allowance for inventory obsolescence. The foreign tax credits will expire in varying amounts from 2021 to 2026.

At December 31, 2016, the Company had U.S. federal net operating loss (“NOL”) carryforwards of $36.6 million, and state NOL carryforwards of $50.9 million. At December 31, 2016, the Company had foreign NOL carryforwards of $2.1 million, $3.2 million, $11.7 million and $1.0 million for India, Thailand, Brazil and Mexico respectively. The U.S. federal NOL carryforwards will expire in 2036. The NOL carryforwards for states will expire between 2021 and 2036. The NOL carryforwards for Thailand and India will expire after 2019 and 2022, respectively. The NOL carryforwards for Brazil can be carried forward indefinitely.

Appropriate U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted in the future. The cumulative amount of undistributed earnings of foreign subsidiaries that the Company intends to indefinitely reinvest, and upon which foreign taxes have been accrued or paid but no deferred U.S. income taxes have been provided is approximately $240 million at December 31, 2016, the majority of which has been generated in the United Kingdom (before the Company’s representation to permanently reinvest earnings in the United Kingdom was removed) and Singapore. If distribution of these earnings in the form of dividends or otherwise were to occur, the Company may be subject to U.S. income taxes (subject to adjustment for foreign tax credits) and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. During 2016 and 2015, we repatriated $20.1 million and $35.2 million, respectively, from our foreign subsidiaries which was used to reduce outstanding borrowings under our revolving credit facility.

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

Tax years subsequent to 2013 remain open to U.S. federal tax audit. Our foreign subsidiaries' federal tax returns subsequent to 2010 are subject to audit by the various foreign tax authorities.

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

The total amount of unrecognized tax benefits as of December 31, 2016, 2015 and 2014 was nil. The Company accrues interest and penalties related to unrecognized tax benefits as a component of the Company's provision for income taxes. As of December 31, 2016 and 2015, the Company had no accrued interest expense or penalties.

15. Stock-Based and Deferred Compensation Plans

Current accounting standards require companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value of stock option awards is estimated using option-pricing models. The fair value of service-based and performance-based restricted stock awarded is determined by the quoted market price of the Company’s common stock on the date of grant, except for a limited number of performance-based restricted awards which are valued using a Monte Carlo simulation model as a result of the inclusion of performance metrics that are not based solely on the performance of our Company’s common stock. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period.

Stock-based compensation pre-tax expense from continuing operations recognized in the years ended December 31, 2016, 2015 and 2014 totaled $21.3 million, $21.8 million and $25.6 million, respectively.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Stock Options

The fair value of each option grant is estimated on the date of grant using a Black Scholes Merton option pricing model that uses the assumptions noted in the following table. The risk-free interest rate is based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2015 and 2014 (no options were awarded in 2016) was based on a formula considering the vesting period, term of the options awarded and past experience.

	2015		2014
Risk-free weighted interest rate		1.2%		1.3%
Expected life (in years)		4.3		4.1
Expected volatility		37%		38%

The following table presents the changes in stock options outstanding and related information for the year ended December 31, 2016:

	Options			Weighted Average Exercise Price		Weighted Average Contractual Life (Years)		Aggregate Intrinsic Value (thousands)
Outstanding Options at December 31, 2015		770,181		$	48.49		7.0	$	88
Exercised		(16,714	)		24.89
Forfeited/Expired		(38,372	)		48.40
Outstanding Options at December 31, 2016		715,095			49.11		6.2		–


Exercisable Options at December 31, 2016		494,504		$	48.86		5.7	$	–

The weighted average fair values of options granted during 2015 and 2014 were $13.32 and $32.03 per share, respectively. All options awarded in 2015 had a term of ten years and were granted with exercise prices at the grant date closing market price. The total intrinsic value of options exercised during 2016, 2015, and 2014 were $0.4 million, $12.4 million, and $28.1 million, respectively. Cash received by the Company from option exercises during 2016, 2015, and 2014 totaled $0.4 million, $5.9 million, and $10.5 million, respectively. The tax benefit realized for the tax deduction from stock options exercised during 2016, 2015 and 2014 totaled less than $0.1 million, $6.5 million, and $6.9 million, respectively.

The following table summarizes information for stock options outstanding as of December 31, 2016:

			Options Outstanding						Options Exercisable
Range of Exercise Prices			Options Outstanding		Weighted Average Contractual Life (Years)		Weighted Average Exercise Price		Options Exercisable		Weighted Average Exercise Price
$41.49	-	$ 46.78		384,672		6.3	$	44.74		251,560	$	45.20
$49.33	-	$ 49.33		155,372		5.1		49.33		155,372		49.33
$58.54	-	$ 58.54		175,051		7.1		58.54		87,572		58.54
				715,095		6.2		49.11		494,504		48.86

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Restricted Stock Awards

The restricted stock program consists of a combination of service-based restricted stock and performance-based restricted stock. The number of performance-based restricted shares ultimately issued under the program is dependent upon our achievement of a predefined specific performance measures generally measured over a three-year period. The performance measure for the 2016 awards is relative total stockholder return compared to our peer group of companies while the performance measure specified for the 2015 and 2014 awards was average after-tax return on invested capital. The 2014 performance metric threshold was not achieved and no performance-based equity was earned for this award. Currently, it is unlikely that the 2015 performance measure threshold will be met which would result in an additional performance forfeiture of 80,000 shares in 2017.

In the event the predefined targets are exceeded for any performance-based award, additional shares up to a maximum of 200% of the target award may be granted. Conversely, if actual performance falls below the predefined target, the number of shares vested is reduced. If the actual performance falls below the threshold performance level, no restricted shares will vest. The time-based restricted stock generally vest on a straight-line basis over their term, which is generally three to four years.

The following table presents the changes of restricted stock awards and related information for 2016:

	Service-based Restricted Stock					Performance-based Restricted Stock
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Grant Date Fair Value		Total Number of Restricted Shares
Unvested, December 31, 2015		1,047,084		$	43.08		124,800		$	50.16		1,171,884
Granted		623,584			25.52		86,462			37.93		710,046
Performance adjustment		–			–		(46,850	)		62.37		(46,850	)
Vested		(472,946	)		24.88		–					(472,946	)
Forfeited		(57,233	)		38.08		(6,487	)		47.52		(63,720	)
Unvested, December 31, 2016		1,140,489			35.07		157,925			39.95		1,298,414

The weighted average grant date fair value per share for restricted stock awards granted in 2016, 2015 and 2014 was $25.52, $42.39, and $93.09, respectively. The total fair value of restricted stock awards vested in 2016, 2015 and 2014 was $11.8 million, $18.9 million, and $27.2 million, respectively. As of December 31, 2016, there was $27.9 million of total compensation costs related to nonvested restricted stock awards not yet recognized, which is expected to be recognized over a weighted average vesting period of two years.

At December 31, 2016, a total of 1,276,175 shares were available for future grant under the Equity Participation Plan.

Deferred Compensation Plan

The Company maintains a nonqualified deferred compensation plan (the Deferred Compensation Plan) that permits eligible employees and directors to elect to defer the receipt of all or a portion of their directors’ fees and/or salary and annual bonuses. Employee contributions to the Deferred Compensation Plan are matched by the Company at the same percentage as if the employee was a participant in the Company's 401(k) Retirement Plan and was not subject to the IRS limitations on match-eligible compensation. The Deferred Compensation Plan also permits the Company to make discretionary contributions to any employee's account, although none have been made to date. Director's contributions are not matched by the Company. Since inception of the plan, this discretionary contribution provision has been limited to a matching of the participants' contributions on a basis equivalent to matching permitted under the Company's 401(k) Retirement Savings Plan. The vesting of contributions to the participants’ accounts is also equivalent to the vesting requirements of the Company's 401(k) Retirement Savings Plan. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (the “Trust”) and, therefore, are available to satisfy the claims of the Company's creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest the assets in their individual accounts, including any discretionary contributions by the Company, in ten pre-approved mutual funds held by the Trust which cover a variety of securities and mutual funds. In addition, participants currently have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e. cash or mutual funds) in the participants' individual accounts within the Trust. Company contributions are in the form of cash. Distributions from the plan are generally made upon the participants' termination as a director and/or employee, as applicable, of the Company. Participants receive payments from the Deferred Compensation Plan in cash. At December 31, 2016, Trust assets totaled $18.8 million, the majority of which is classified as “Other noncurrent assets” in the Company’s Consolidated Balance Sheet. The fair value of the investments was based on quoted market prices in active markets (a Level 1 fair value measurement). Amounts payable to the plan participants at December 31, 2016, including the fair value of the shares of the Company's common stock that are reflected as treasury stock, was $19.0 million and is classified as "Other noncurrent liabilities" in the consolidated balance sheet. The Company accounts for the Deferred Compensation Plan in accordance with current accounting standards regarding the accounting for deferred compensation arrangements where amounts earned are held in a Rabbi Trust and invested.

- 81 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

In accordance with current accounting standards, all fair value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of operations. Increases or decreases in the fair value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of operations.

16. Segment and Related Information

The Company operates through two reportable segments: Well Site Services and Offshore Products. The Company's reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technologies and marketing strategies. Acquisitions have been direct extensions to our business segments. Separate business lines within the Well Site Services segment have been disclosed to provide additional detail for that segment.

Financial information by business segment for each of the three years ended December 31, 2016, 2015 and 2014, is summarized in the following table in thousands. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

- 82 -

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	Revenues		Depreciation and amortization		Operating income (loss)			Equity in income of unconsolidated affiliates		Capital expenditures		Total assets
2016
Well Site Services -
Completion services	$	163,060	$	70,031	$	(83,636	)	$	–	$	10,418	$	467,387
Drilling services		22,594		23,366		(24,239	)		–		962		78,081
Total Well Site Services		185,654		93,397		(107,875	)		–		11,380		545,468
Offshore Products		508,790		24,205		87,084			224		17,515		810,464
Corporate		–		1,118		(48,492	)		–		794		27,966
Total	$	694,444	$	118,720	$	(69,283	)	$	224	$	29,689	$	1,383,898

2015
Well Site Services -
Completion services	$	308,077	$	75,612	$	(26,280	)	$	–	$	55,336	$	525,012
Drilling services		67,782		26,889		(17,866	)		–		12,097		103,156
Total Well Site Services		375,859		102,501		(44,146	)		–		67,433		628,168
Offshore Products		724,118		27,416		146,389			526		46,615		930,871
Corporate		–		1,340		(47,237	)		–		690		37,432
Total	$	1,099,977	$	131,257	$	55,006		$	526	$	114,738	$	1,596,471

2014
Well Site Services -
Completion services	$	656,862	$	74,176	$	148,787		$	–	$	107,580	$	641,725
Drilling services		201,143		27,081		29,574			–		29,359		135,676
Total Well Site Services		858,005		101,257		178,361			–		136,939		777,401
Offshore Products		961,604		22,496		200,098			378		60,263		983,542
Corporate		–		1,023		(68,204	)		–		2,054		45,224
Total	$	1,819,609	$	124,776	$	310,255		$	378	$	199,256	$	1,806,167

Financial information by geographic location for each of the three years ended December 31, 2016, 2015 and 2014, is summarized below in thousands. Revenues are attributable to countries based on the location of the entity selling the products or performing the services and include export sales. Long-lived assets are attributable to countries based on the physical location of the operations and its operating assets and do not include intercompany balances.

	United States		United Kingdom		Singapore		Other		Total
2016
Revenues from unaffiliated customers	$	493,615	$	111,565	$	34,577	$	54,687	$	694,444
Long-lived assets		729,699		65,675		23,972		74,454		893,800
2015
Revenues from unaffiliated customers	$	797,762	$	170,536	$	66,305	$	65,374	$	1,099,977
Long-lived assets		817,797		74,082		26,462		66,619		984,960
2014
Revenues from unaffiliated customers	$	1,468,202	$	188,753	$	83,493	$	79,161	$	1,819,609
Long-lived assets		823,203		54,868		27,438		71,265		976,774

No customers accounted for more than 10% of the Company's revenues in the years ended December 31, 2016, 2015 and 2014. Equity in net income of unconsolidated affiliates is not included in operating income.

18. Quarterly Financial Information (Unaudited)

The following table summarizes quarterly financial information for 2016 and 2015 (in thousands, except per share amounts):

	First Quarter⁽²⁾			Second Quarter⁽³⁾			Third Quarter⁽⁴⁾			Fourth Quarter⁽⁵⁾
2016
Revenues	$	169,655		$	175,849		$	179,006		$	169,934
Gross profit⁽¹⁾		40,840			39,449			43,240			44,144
Net income attributable to:
Continuing operations		(13,236	)		(11,705	)		(10,818	)		(10,627	)
Discontinued operations		(3	)		(1	)		–			–
Basic earnings per share:
Continuing operations		(0.26	)		(0.23	)		(0.22	)		(0.21	)
Discontinued operations		–			–			–			–
Diluted earnings per share:
Continuing operations		(0.26	)		(0.23	)		(0.22	)		(0.21	)
Discontinued operations		–			–			–			–
2015
Revenues	$	337,358		$	269,258		$	258,886		$	234,474
Gross profit⁽¹⁾		99,636			74,594			70,296			69,752
Net income attributable to:
Continuing operations		19,402			6,148			1,706			1,115
Discontinued operations		166			35			23			2
Basic earnings per share:
Continuing operations		0.38			0.12			0.03			0.02
Discontinued operations		–			–			–			–
Diluted earnings per share:
Continuing operations		0.38			0.12			0.03			0.02
Discontinued operations		–			–			–			–

(1)

Represents "product and service revenues" less "product and service costs" included in the Company's consolidated statements of operations.

(2)

During the first quarter of 2016, we recognized $1.6 million (pre-tax) of severance and other downsizing charges. Our first quarter 2015 net income attributable to continuing operations included $2.1 million (pre-tax) of severance and other downsizing initiatives, and a higher effective tax rate driven primarily by a $2.3 million deferred tax adjustment for certain prior period non-deductible items.

(3)

During the second quarter of 2016, we recognized $1.1 million (pre-tax) of severance and other downsizing charges. In the second quarter of 2015, we recognized $1.7 million (pre-tax) of severance and other downsizing charges.

(4)

During the third quarter of 2016, we recognized $2.0 million (pre-tax) of severance and other downsizing charges. Our third quarter 2015 net income attributable to continuing operations included a higher effective tax rate driven primarily by a $3.2 million valuation allowance recorded against the Company’s deferred tax assets related to loss carryforwards and $0.7 million (pre-tax) of severance related costs.

(5)

During the fourth quarter of 2016, we recognized $0.6 million (pre-tax) of severance and other downsizing charges. In the fourth quarter of 2015, we recognized a $3.4 million (pre-tax) leasehold restoration provision for one of our Offshore Products U.K. facilities, $1.9 million (pre-tax) of severance and other downsizing charges, and a higher effective tax rate driven primarily by $1.2 million in tax adjustments primarily related to non-deductible items and a $0.6 million valuation allowance recorded against the Company’s tax loss carryforwards in various foreign jurisdictions.

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

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

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

Large accelerated filer [X]	Accelerated filer [ ]

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

●	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;

●	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.

	●	retaining key employees of acquired businesses;

	●	retaining and attracting new customers of acquired businesses;

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

	●	increased administrative burden;

	●	developing our sales and marketing capabilities;

	●	managing our growth effectively;

	●	potential goodwill impairment resulting from the overpayment for an acquisition;

	●	integrating operations;

	●	managing tax and foreign exchange exposure;

	●	operating a new line of business;

	●	increased logistical problems common to large, expansive operations;

	●	inability to pursue and protect patents covering acquired technology; and

	●	becoming subject to unanticipated liabilities of the acquired business.

PART I		Page
Cautionary Statement Regarding Forward-Looking Statements		3
Item 1.	Business	4
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	31
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	49
Item 9A.	Controls and Procedures	49
Item 9B.	Other Information	50

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	51
Item 11.	Executive Compensation	51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
Item 14.	Principal Accounting Fees and Services	51

PART IV
Item 15.	Exhibits, Financial Statement Schedules	52
SIGNATURES		56
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		57

	Price
	High		Low
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
2015
First Quarter	$	49.31	$	38.41
Second Quarter		48.16		36.30
Third Quarter		37.27		23.35
Fourth Quarter		33.14		24.24

Period	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share	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, 2016	212	$ 30.30	–	$ 136,827,937
November 1 through November 30, 2016	–	–	–	$ 136,827,937
December 1 through December 31, 2016	634	$ 36.95	–	$ 136,827,937
Total	846	$ 35.28	–	$ 136,827,937

	As of December 31,
	2016		2015		2014		2013		2012
Balance Sheet Data:
Cash and cash equivalents	$	68,800	$	35,973	$	53,263	$	599,306	$	253,172
Current assets held for sale⁽²⁾		–		–		–		–		632,496
Total current assets		489,977		611,473		826,666		1,525,907		1,826,092
Property, plant and equipment, net		553,402		638,725		649,846		1,902,789		1,827,242
Noncurrent assets held for sale⁽²⁾		–		–		–		–		31,605
Total assets⁽⁴⁾		1,383,898		1,596,471		1,806,167		4,109,863		4,407,179
Long-term debt and capital leases, excluding current portion⁽⁴⁾		45,388		125,887		143,390		951,294		1,247,023
Total stockholders' equity		1,204,307		1,255,672		1,340,657		2,625,294		2,465,800

	(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. The Company has included EBITDA as defined as a supplemental disclosure because its management believes that EBITDA as defined provides useful information regarding its ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing its operating performance with the performance of other companies that have different financing and capital structures or tax rates. The Company uses EBITDA as defined to compare and to monitor the performance of its business segments to other comparable public companies and as a benchmark for the award of incentive compensation under its annual incentive compensation plan.

	(4)	In 2016, we adopted recently issued accounting guidance with respect to the balance sheet presentation of deferred financing costs. Prior year amounts have been adjusted to reflect the reclassification of such costs in the prior year balance sheets to conform to the current year presentation.

	Average Price ⁽¹⁾
	WTI		Brent		Henry Hub
	Crude		Crude		Natural Gas
Quarter Ended	(per bbl)		(per bbl)		(per mmBtu)
December 31, 2016	$	49.14	$	49.11	$	3.04
September 30, 2016		44.85		45.80		2.88
June 30, 2016		45.46		45.57		2.15
March 31, 2016		33.35		33.84		1.99
December 31, 2015		41.94		43.56		2.12
September 30, 2015		46.49		50.44		2.76
June 30, 2015		57.85		61.65		2.75
March 31, 2015		48.49		53.98		2.90
December 31, 2014		73.21		76.43		3.78
September 30, 2014		97.87		101.90		3.96
June 30, 2014		103.35		109.69		4.61
March 31, 2014		98.68		108.14		5.18

	As of February 10,		Average Rig Count for Year Ended December 31,
	2017		2016		2015		2014		2013		2012
U.S. Land – Oil		571		390		723		1,486		1,334		1,335
U.S. Land - Natural gas and other		146		97		219		319		371		537
U.S. Offshore		24		25		35		57		56		47
Total U.S.		741		512		977		1,862		1,761		1,919
Canada		352		129		193		380		355		365
Total North America		1,093		641		1,170		2,242		2,116		2,284

	Years Ended December 31,
							Variance 2016 vs. 2015								Variance 2015 vs. 2014
	2016			2015			$			%		2014			$			%
Revenues
Well Site Services -
Completion Services	$	163,060		$	308,077		$	(145,017	)		(47)%	$	656,862		$	(348,785	)		(53)%
Drilling Services		22,594			67,782			(45,188	)		(67)%		201,143			(133,361	)		(66)%
Total Well Site Services		185,654			375,859			(190,205	)		(51)%		858,005			(482,146	)		(56)%
Offshore Products		508,790			724,118			(215,328	)		(30)%		961,604			(237,486	)		(25)%
Total	$	694,444		$	1,099,977		$	(405,533	)		(37)%	$	1,819,609		$	(719,632	)		(40)%
Product and service costs
Well Site Services -
Completion Services	$	153,356		$	237,441		$	(84,085	)		(35)%	$	402,942		$	(165,501	)		(41)%
Drilling Services		21,797			56,274			(34,477	)		(61)%		141,369			(85,095	)		(60)%
Total Well Site Services		175,153			293,715			(118,562	)		(40)%		544,311			(250,596	)		(46)%
Offshore Products		351,617			491,983			(140,366	)		(29)%		661,573			(169,590	)		(26)%
Total	$	526,770		$	785,698		$	(258,928	)		(33)%	$	1,205,884		$	(420,186	)		(35)%
Gross profit
Well Site Services -
Completion Services	$	9,704		$	70,636		$	(60,932	)		(86)%	$	253,920		$	(183,284	)		(72)%
Drilling Services		797			11,508			(10,711	)		(93)%		59,774			(48,266	)		(81)%
Total Well Site Services		10,501			82,144			(71,643	)		(87)%		313,694			(231,550	)		(74)%
Offshore Products		157,173			232,135			(74,962	)		(32)%		300,031			(67,896	)		(23)%
Total	$	167,674		$	314,279		$	(146,605	)		(47)%	$	613,725		$	(299,446	)		(49)%
Gross profit as a percentage of revenues
Well Site Services -
Completion Services		6	%		23	%							39	%
Drilling Services		4	%		17	%							30	%
Total Well Site Services		6	%		22	%							37	%
Offshore Products		31	%		32	%							31	%
Total		24	%		29	%							34	%

	Payments due by period
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Contractual obligations
Total debt, including capital leases⁽¹⁾	$	45,926	$	538	$	41,021	$	733	$	3,634
Purchase obligations⁽²⁾		32,291		30,558		1,733		-		-
Non-cancelable operating lease obligations⁽³⁾		27,104		7,981		10,910		3,837		4,376
Total contractual cash obligations	$	105,321	$	39,077	$	53,664	$	4,570	$	8,010

Exhibit No.		Description

2.1	—	Separation and Distribution Agreement by and between Oil States International, Inc. and Civeo Corporation, dated May 27, 2014 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

3.1	—	Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

3.2	—	Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).

3.3	—	Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

4.1	—	Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on November 7, 2000 (File No. 333-43400)).

4.2	—	Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

4.3	—	First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003 (File No. 001-16337)).

4.4	—	Third Supplemental Indenture dated as of May 29, 2014 to Indenture dated as of June 1, 2011, by and among Oil States International, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

4.5	—	Supplemental Indenture dated as of May 29, 2014 to Indenture dated as of December 21, 2012, by and among Oil States International, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.1	—	Combination Agreement dated as of July 31, 2000 by and among Oil States International, Inc., HWC Energy Services, Inc., Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI Group Inc. (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on August 10, 2000 (File No. 333-43400)).

10.2*+	—	Second Amended and Restated 2001 Equity Participation Plan effective January 1, 2017.

10.3+	—	Deferred Compensation Plan effective January 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as filed with the Commission on April 25, 2013 (File No. 001-16337)).

10.4*+	—	Annual Incentive Compensation Plan, dated January 1, 2017.

10.5+	—	Executive Agreement between Oil States International, Inc. and Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

10.6+	—	Form of Change of Control Severance Plan for Selected Members of Management (incorporated by reference to Exhibit 10.11 of the Company's Registration Statement on Form S-1, as filed with the Commission on December 12, 2000 (File No. 333-43400)).

10.7	—	Credit Agreement, dated as of May 28, 2014, among Oil States International, Inc., as Borrower, the Lenders from time to time 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, (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.8	—	Consent and Amendment No. 1 to Credit Agreement, dated as of May 28, 2014, among Oil States International, Inc., as borrower, the guarantors named therein, the lenders named therein (the “Lenders”), and Wells Fargo Bank, N.A., as administrative agent. (incorporated by reference to Exhibit 10.1 to the Company’s Report on Form 8-K as filed with the Commission on October 5, 2016 (File No. 001-16337)).

10.9	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004 (File No. 001-16337)).

10.10+	—	Form of Director Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.11*+	—	Form of Employee Non Qualified Stock Option Agreement under the Company's Second Amended and Restated 2001 Equity Participation Plan.

10.12*+	—	Form of Restricted Stock Agreement under the Company's Second Amended and Restated 2001 Equity Participation Plan.

10.13*+	—	Form of Deferred Stock Performance Award Agreement under the Company’s Second Amended and Restated 2001 Equity Participation Plan.

10.14+	—	Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company's Report on Form 8-K as filed with the Commission on November 15, 2006 (File No. 001-16337)).

10.15+	—	Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005 (File No. 001-16337)).

10.16+	—	Form of Non-Employee Director Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.22 to the Company's Report on Form 8-K, as filed with the Commission on May 24, 2005 (File No. 001-16337)).

10.17+	—	Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009 (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

10.18+	—	Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009 (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).

10.19+	—	Deferred Stock Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on February 23, 2012 (File No. 001-16337)).

10.20+	—	Deferred Stock Agreement effective February 19, 2013 (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as filed with the Commission on April 25, 2013 (File No. 001-16337)).

10.21+	—	Executive Agreement between Oil States International, Inc. and named executive officer (Lloyd A. Hajdik) effective December 9, 2013 (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the Commission on February 25, 2014 (File No. 001-16337)).

10.22+	—	Executive Agreement between Oil States International, Inc. and named executive officer (Lias J. Steen) effective May, 20, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, as filed with the Commission on May 2, 2014 (File No. 001-16337)).

10.23	—	Indemnification and Release Agreement by and between Oil States International, Inc. and Civeo Corporation, dated May 27, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.24	—	Tax Sharing Agreement by and between Oil States International, Inc. and Civeo Corporation, dated May 27, 2014 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.25	—	Employee Matters Agreement by and between Oil States International, Inc. and Civeo Corporation, dated May 27, 2014 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.26	—	Transition Services Agreement by and between Oil States International, Inc. and Civeo Corporation, dated May 27, 2014 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 2, 2014 (File No. 001-16337)).

10.27+	—	Executive Agreement between Oil States International, Inc. and named executive officer (Philip S. Moses) effective July, 1, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, as filed with the Commission on July 8, 2015 (File No. 001-16337)).

21.1*	—	List of subsidiaries of the Company.

23.1*	—	Consent of Independent Registered Public Accounting Firm.

24.1*	—	Powers of Attorney for Directors.

31.1*	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.

31.2*	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.

32.1**	—	Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.

32.2**	—	Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.

101.INS*	—	XBRL Instance Document

101.SCH*	—	XBRL Taxonomy Extension Schema Document

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

	OIL STATES INTERNATIONAL, INC.


	By	/s/ CINDY B. TAYLOR
		Cindy B. Taylor
		President and Chief Executive Officer

Signature		Title

/s/ MARK G. PAPA*		Chairman of the Board
Mark G. Papa

/s/ CINDY B. TAYLOR		Director, President & Chief Executive Officer
Cindy B. Taylor		(Principal Executive Officer)

/s/ LLOYD A. HAJDIK		Executive Vice President, Chief Financial Officer
Lloyd A. Hajdik		and Treasurer
		(Principal Financial Officer)

/s/ BRIAN E. TAYLOR		Vice President, Controller and Chief Accounting Officer
Brian E. Taylor		(Principal Accounting Officer)

/s/ LAWRENCE R. DICKERSON*		Director
Lawrence R. Dickerson

/s/ S. JAMES NELSON, JR.*		Director
S. James Nelson, Jr.

/s/ GARY L. ROSENTHAL*		Director
Gary L. Rosenthal

/s/ CHRISTOPHER T. SEAVER*		Director
Christopher T. Seaver

/s/ WILLIAM T. VAN KLEEF*		Director
William T. Van Kleef

/s/ STEPHEN A. WELLS*		Director
Stephen A. Wells


*By:	/s/ LLOYD A. HAJDIK
Lloyd A. Hajdik, pursuant to a power of
attorney filed as Exhibit 24.1 to this
Annual Report on Form 10-K

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	58
Report of Independent Registered Public Accounting Firm on the Company's Internal Control Over Financial Reporting	59
Consolidated Statements of Operations	60
Consolidated Statements of Comprehensive Income (Loss)	61
Consolidated Balance Sheets	62
Consolidated Statements of Stockholders' Equity	63
Consolidated Statements of Cash Flows	64
Notes to Consolidated Financial Statements	65

	December 31,
	2016			2015
ASSETS

Current assets:
Cash and cash equivalents	$	68,800		$	35,973
Accounts receivable, net		234,513			333,494
Inventories, net		175,490			212,882
Prepaid expenses and other current assets		11,174			29,124
Total current assets		489,977			611,473

Property, plant and equipment, net		553,402			638,725
Goodwill, net		263,369			263,787
Other intangible assets, net		52,746			59,385
Other noncurrent assets		24,404			23,101
Total assets	$	1,383,898		$	1,596,471

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Current portion of long-term debt and capitalized leases	$	538		$	533
Accounts payable		34,207			59,116
Accrued liabilities		45,018			49,300
Income taxes payable		5,839			8,303
Deferred revenue		21,315			36,655
Other current liabilities		315			293
Total current liabilities		107,232			154,200

Long-term debt and capitalized leases		45,388			125,887
Deferred income taxes		5,036			40,497
Other noncurrent liabilities		21,935			20,215
Total liabilities		179,591			340,799

Stockholders' equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 62,295,870 shares and 61,712,805 shares issued, respectively		623			617
Additional paid-in capital		731,562			712,980
Retained earnings		1,133,473			1,179,863
Accumulated other comprehensive loss		(70,300	)		(50,698	)
Treasury stock at cost, 10,921,509 and 10,759,656 shares, respectively		(591,051	)		(587,090	)
Total stockholders' equity		1,204,307			1,255,672
Total liabilities and stockholders' equity	$	1,383,898		$	1,596,471

	2016			2015
Accounts receivable, net:
Trade	$	173,087		$	210,313
Unbilled revenue		64,564			124,331
Other		5,372			5,738
Total accounts receivable		243,023			340,382
Allowance for doubtful accounts		(8,510	)		(6,888	)
	$	234,513		$	333,494

	2016			2015
Inventories, net:
Finished goods and purchased products	$	87,241		$	97,362
Work in process		30,584			42,182
Raw materials		72,514			86,236
Total inventories		190,339			225,780
Allowance for excess, damaged, or obsolete inventory		(14,849	)		(12,898	)
	$	175,490		$	212,882

	2016		2015
Prepaid expenses and other current assets:
Prepayments to vendors	$	877	$	5,266
Prepaid insurance		3,738		4,827
Income tax asset		430		11,519
Prepaid non-income taxes		1,650		1,680
Prepaid rent		602		1,108
Other		3,877		4,724
	$	11,174	$	29,124

	Estimated Useful Life (in years)			2016			2015
Property, plant and equipment, net:
Land				$	31,683		$	26,334
Buildings and leasehold improvements	3	-	40		227,642			185,274
Machinery and equipment	2	-	28		455,873			462,054
Completion services equipment	2	-	10		429,845			421,386
Office furniture and equipment	3	-	10		42,827			32,200
Vehicles	2	-	10		121,317			125,211
Construction in progress					27,519			92,800
Total property, plant and equipment					1,336,706			1,345,259
Accumulated depreciation					(783,304	)		(706,534	)
				$	553,402		$	638,725

	2016		2015
Accrued liabilities:
Accrued compensation	$	23,131	$	19,402
Insurance liabilities		8,099		9,855
Accrued taxes, other than income taxes		2,461		3,619
Accrued leasehold restoration liability		766		3,389
Accrued commissions		1,305		2,033
Accrued product warranty reserves		1,113		2,638
Accrued claims		1,578		896
Other		6,565		7,468
	$	45,018	$	49,300

	2015
Fair value of assets acquired including intangibles and goodwill	$	39,505
Liabilities assumed		(6,026	)
Cash acquired		(52	)
Cash used in acquisition of business	$	33,427

Basic net income (loss) per share attributable to Oil States from:
Continuing operations	$	(0.92	)	$	0.55	$	2.37
Discontinued operations		–			0.01		0.96
Net income (loss)	$	(0.92	)	$	0.56	$	3.33

Diluted net income (loss) per share attributable to Oil States from:
Continuing operations	$	(0.92	)	$	0.55	$	2.35
Discontinued operations		–			0.01		0.96
Net income (loss)	$	(0.92	)	$	0.56	$	3.31

	Operating Leases
2017	$	7,981
2018		6,286
2019		4,624
2020		2,467
2021		1,370
Thereafter		4,376
Total	$	27,104

	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (net of recoveries)			Translation and Other, Net			Balance at End of Period
Year Ended December 31, 2016:
Allowance for doubtful accounts receivable	$	6,888	$	2,275	$	(400	)	$	(253	)	$	8,510
Allowance for excess, damaged or obsolete inventory		12,898		4,916		(2,756	)		(209	)		14,849
Valuation allowance on deferred tax assets		3,970		2,279		–			784			7,033
Year Ended December 31, 2015:
Allowance for doubtful accounts receivable	$	7,125	$	195	$	(187	)	$	(245	)	$	6,888
Allowance for excess, damaged or obsolete inventory		9,876		5,487		(2,395	)		(70	)		12,898
Valuation allowance on deferred tax assets		–		3,970		–			–			3,970
Year Ended December 31, 2014:
Allowance for doubtful accounts receivable	$	3,878	$	3,364	$	111		$	(228	)	$	7,125
Allowance for excess, damaged or obsolete inventory		9,540		2,147		(1,772	)		(39	)		9,876