Edgar Filing: OIL STATES INTERNATIONAL, INC

ois20151231_10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ________

Commission file no. 001-16337

Oil States International, Inc.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:

(713) 652-0582

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

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

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) YES [X ] NO [ ]

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [X]	Accelerated filer [ ]

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

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

The aggregate market value of the voting and non-voting common stock held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2015, was $1,840,219,502.

The number of shares of the registrant’s common stock, par value $0.01 per share, outstanding as of February 18, 2016 was 51,449,961 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, which the registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K, are incorporated by reference into Part III of this Annual Report on Form 10-K.

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TABLE OF CONTENTS

PART I		Page
Cautionary Statement Regarding Forward-Looking Statements		4 – 5
Item 1.	Business	5 – 19
Item 1A.	Risk Factors	19 – 32
Item 1B.	Unresolved Staff Comments		33
Item 2.	Properties	33
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures		34

PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34 – 37
Item 6.	Selected Financial Data	38– 40
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	40 – 55
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		56
Item 8.	Financial Statements and Supplementary Data		56
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		57
Item 9A.	Controls and Procedures	57 – 58
Item 9B.	Other Information		58

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		58
Item 11.	Executive Compensation		58
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		58
Item 13.	Certain Relationships and Related Transactions, and Director Independence		58
Item 14.	Principal Accounting Fees and Services		58

PART IV
Item 15.	Exhibits, Financial Statement Schedules	59 – 62
SIGNATURES			63
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			64

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PART I

This Annual Report on Form 10-K contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of known material factors that could affect our results, please refer to “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” below.

Cautionary Statement Regarding Forward-Looking Statements

We include the following cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any "forward-looking statement" made by us, or on our behalf. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. You can typically identify "forward-looking statements" by the use of forward-looking words such as "may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast," “proposed,” “should,” “seek,” and other similar words. Such statements may include statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.

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

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

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

	●	the level of drilling and completion activity;

	●	the financial health of our customers;

	●	the availability of attractive oil and natural gas field prospects, which may be affected by governmental actions or actions of other parties which may restrict drilling;

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

	●	general global economic conditions;

	●	global weather conditions and natural disasters;

	●	our ability to find and retain skilled personnel;

	●	the availability and cost of capital; and

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

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

Item 1. Business

Our Company

Oil States International, Inc. (the Company or Oil States), through its subsidiaries, is a leading provider of specialty products and services to oil and natural gas companies throughout the world. With the completion of the spin-off of our accommodations business, we are now a technology-focused, pure-play energy services company. We operate in some of the world's most active oil and natural gas producing regions, including onshore and offshore U.S., Canada, West Africa, the North Sea, South America and Southeast and Central Asia. Our customers include many national oil companies, major and independent oil and natural gas companies, onshore and offshore drilling companies and other oilfield service companies. We operate in two principal 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 our subsidiaries.

Available Information

The Company maintains a website with the address of www.oilstatesintl.com. The Company is not including the information contained on the Company's website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K. The Company makes available free of charge through its website its Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after the Company electronically files such material with, or furnishes such material to, the Securities and Exchange Commission (the Commission). The filings are also available through the Commission at the Commission's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The Board of Directors of the Company (the Board) has documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company's Corporate Governance Guidelines, Corporate Code of Business Conduct and Ethics and Financial Code of Ethics for Senior Officers, as well as the charters for the committees of the Board (Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee) may also be viewed at the Company's website. The financial code of ethics applies to our principal executive officer, principal financial officer, principal accounting officer and other senior officers. Copies of such documents will be sent to shareholders free of charge upon written request to the corporate secretary at the address shown on the cover page of this Annual Report on Form 10-K.

Our Business Strategy

We have in past years grown our business lines both organically through capital spending and through strategic acquisitions. Our investments are focused in growth areas and on areas where we expect we can expand market share and where we believe we can achieve an attractive return on our investment. We have seen investment opportunities in shale play regions in North America and in the expansion of our capabilities to manufacture and assemble deepwater capital equipment on a global basis. 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 shareholders’ returns. For additional discussion of our business strategy, please read Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Capital Spending and Acquisitions

Capital spending over the last several years has included both growth and maintenance capital expenditures in each of our businesses. Capital spending totaled $479 million over the three-year period 2013 to 2015.

In addition to capital spending, we have invested $78 million over the three-year period 2013 to 2015 for acquisitions of businesses. Acquisitions of other oilfield service businesses have been an important aspect of our growth strategy and plan to increase shareholder value. Our acquisition strategy has allowed us to leverage our existing and acquired products and services into new geographic locations, and has expanded our technology and product offerings. We have made strategic acquisitions in each of our business segments in recent years.

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On January 2, 2015, we acquired all of the equity of Montgomery Machine Company, Inc. (MMC). Headquartered in Houston, Texas, MMC combines machining and proprietary cladding technology and services to manufacture high-specification components for the offshore capital equipment industry on a global basis. We believe that the acquisition of MMC will strengthen our position in our offshore products segment 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.

On December 2, 2013, we acquired all of the operating assets of Quality Connector Systems, LLC (QCS) for total cash consideration of $42.3 million. Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. The operations of QCS have been included in our offshore products segment since the acquisition date.

The Company funded these acquisitions with cash on hand and/or amounts available under our credit facilities. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.

Our Industry

We principally operate in the oilfield services industry and provide a broad range of products and services to our customers through each of our business segments. See Note 16 to the Consolidated Financial Statements included in “Part II, Item 8. Financial Statements and Supplementary Data” for financial information by segment and a geographical breakout of revenues and long-lived assets for each of the three years ended December 31, 2015, 2014 and 2013. 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 on the exploration for and development of oil and natural gas. Our customers’ capital spending programs are generally based on their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is largely sensitive to expected commodity prices, principally related to crude oil and natural gas.

Our historical financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments. For additional information about activities in each of our segments, please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

During 2013 and the first three quarters of 2014, we benefited from high oil prices resulting in very active bidding and quoting activity for our offshore products segment. However, beginning early in the fourth quarter of 2014 and continuing throughout 2015, crude oil prices decreased significantly. Bidding and quoting activity for our offshore products segment continued during 2015, albeit at a slower pace. Accordingly, backlog in our offshore products segment decreased to $340 million at December 31, 2015 from $490 million at December 31, 2014 and $580 million at December 31, 2013 due to project deferrals and delays in award timing resulting from the continued depressed commodity price environment.

Beginning in the fourth quarter of 2014, crude oil prices began a precipitous fall, with WTI decreasing from a June peak price per barrel of $107.95 to $30.77 per barrel as of February 18, 2016. These materially lower commodity prices have, and may continue to have, a negative impact on the cash flows of our customers forcing them to cut 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 during 2016 along with reduced revenues and profitability. Also due to this environment, we have an increased risk of project cancellations and contractual modifications.

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Our well site services business segment is primarily affected by drilling and completion activity in the U.S., including the Gulf of Mexico, and, to a lesser extent, Canada and the rest of the world. U.S. drilling and completion activity and, thus, our well site services results, are especially sensitive to near-term fluctuations in commodity prices and have, therefore, been significantly negatively affected by the material decline in crude oil prices from 2014 to the current date.

In the past few years, our industry has experienced a shift in 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. According to the most current 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 in recent months due to much lower crude oil prices, totaling 439 rigs as of February 12, 2016. The February 12, 2016 oil rig count comprised approximately 81% of total U.S. drilling activity. The remaining 19% of drilling activity is largely natural gas related. The U.S. natural gas-related working rig count has declined from more than 810 rigs at the beginning of 2012 to 102 rigs as of February 12, 2016, a more than 28 year low. Unless commodity prices improve, we expect that the rig count and demand from our customers for our well site services will remain low during 2016.

In response to the adverse effects in 2015 of the materially lower commodity prices on our results of operations, cash flows and financial position, the Company implemented various cost-saving measures, including the closing of underperforming completion services locations and company-wide headcount reductions that total approximately 33% since the beginning of 2015.

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

Offshore Products

Overview

During the year ended December 31, 2015, we generated approximately 66% of our revenue and 74% of our gross margin from our offshore products segment. Through this segment, we design and manufacture a number of cost-effective, technologically advanced products for the offshore energy industry. In addition, we supply other lower margin products and services such as fabrication and inspection services. Our products and services are used primarily in deepwater producing regions and include flex-element technology, advanced connector systems, high-pressure riser systems, compact valves, deepwater mooring systems, cranes, subsea pipeline products, blow-out preventer stack integration, specialty welding, cladding and machining services, offshore installation services and repair services. We have facilities that support our offshore products segment in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Oklahoma City and Tulsa, Oklahoma; Scotland; Brazil; England; Singapore; Thailand; Vietnam; and India.

Offshore Products Market

The market for our offshore products and services depends primarily upon development of infrastructure for offshore production activities, drilling rig refurbishments and upgrades as well as new rig and vessel construction. Demand for oil and natural gas and related drilling and production in offshore areas throughout the world, particularly in deeper water, drive spending for these activities.

Products and Services

In operation for over 70 years, our offshore products segment provides a broad range of products and services for use in offshore drilling and development activities. To a lesser extent, this segment also provides onshore oil and natural gas, defense and general industrial products and services. Our offshore products segment is dependent in part on the industry's continuing innovation and creative applications of existing technologies. We own 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 subsea equipment and offshore vessel and rig equipment. Our products are components of equipment used for the drilling and production of oil and natural gas wells on offshore fixed platforms and mobile production units, including floating platforms, such as tension leg platforms, floating production, storage and offloading (FPSO) vessels, Spars, and on other marine vessels, floating rigs and jack-up rigs. Our products and services include:

	●	flexible bearings and advanced connection systems;

	●	casing and conductor connections and pipe;

	●	subsea pipeline products;

	●	compact ball valves, manifold system components and diverter valves;

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

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

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

	●	other products and services.

Flexible Bearings and Advanced Connection Systems. We are a significant supplier of flexible bearings, or FlexJoint^®, to the offshore oil and gas industry as well as weld-on connectors and fittings that join lengths of large diameter conductor or casing used in offshore drilling and production operations. A FlexJoint^® is a flexible bearing that permits the controlled movement of riser or tension leg platform tethers under high tension and pressure. A FlexJoint^® or our flex element at the top, bottom and, in some cases, middle of a deepwater riser reduces the stress and tension on the riser compensating for the pitch and rotational forces on the riser as the production facility or drilling rig moves with ocean forces. They are used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water areas. Drilling riser systems provide the vertical conduit between the floating drilling vessel and the subsea wellhead. Through the drilling riser, equipment is guided into the well and drilling fluids are returned to the surface. Production riser systems provide the vertical conduit for the hydrocarbons from the subsea wellhead to the floating production 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^® bearings are a critical element in the construction and operation of production and export risers on floating production systems in deepwater.

Floating production systems, including tension leg platforms, Spars and FPSO facilities, are a significant means of producing oil and natural gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. A tension leg platform (TLP) is a floating platform that is moored by vertical pipes, or tethers, attached to both the platform and the sea floor. Our FlexJoint^® tether bearings are used at the top and bottom connections of each of the tethers, and our Merlin™ connectors are used to efficiently assemble the tethers during offshore installation. An FPSO is a floating vessel, typically ship shaped, used to produce, and process oil and natural gas from subsea wells. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. Our FlexJoint^® bearings are also used to attach the steel catenary risers to an FPSO, tension leg platform or Spar, and for use on import or export risers.

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

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

Subsea Pipeline Products. We design and manufacture a variety of equipment used in the construction, maintenance, expansion and repair of offshore oil and natural gas pipelines. New construction equipment includes:

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pipeline end manifolds and pipeline end terminals;

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deep and shallow water pipeline connectors;

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midline tie-in sleds;

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

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

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electrical isolation joints; and

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

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

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

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

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

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misalignment and swivel ring flanges; and

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pipe recovery tools for recovering dropped or damaged pipelines.

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

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

Marine Winches, Mooring Systems, Cranes and other Heavy-Lift Rig Equipment. We design, engineer and manufacture marine winches, mooring systems, cranes and certain rig equipment. Our Skagit^® winches are specifically designed for mooring floating and semi-submersible drilling rigs and positioning pipelay and derrick barges, anchor handling boats and jack-ups, while our Nautilus^® marine cranes are used on production platforms throughout the world. We also design and fabricate rig equipment such as automatic pipe racking and blow-out preventer handling equipment. Our engineering teams, manufacturing capability and service technicians who install and service our products provide our customers with a broad range of equipment and services to support their operations. Aftermarket service and support of our installed base of equipment to our customers is also an important source of revenue to us. These products are designed at our Houma, Louisiana location and manufactured at our Houma, Louisiana; Navi Mumbai, India; and Rayong, Thailand locations.

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Production, Workover, Completion and Drilling Riser Systems and their related repair services. Utilizing the expertise of our welding technology group, we have extended the boundaries of our Merlin™ connector technology with the design and manufacture of multiple riser systems. The unique Merlin™ connection has proven to be a robust solution for even the most demanding high-pressure (up to 10,000 psi) riser systems used in high-fatigue, deepwater applications. Our riser systems are designed to meet a range of static and fatigue stresses on a par with those of our Tension Leg Elements (TLE) connectors. The connector can be welded or machined directly onto upset riser pipe and provide sufficient material to perform "re-cuts" after extended service. Our marine riser offers 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 we do not manufacture BOP stack assemblies, we design and fabricate lifting and protection frames and offer system integration of blow-out preventer stacks and subsea production trees. We can provide complete turnkey and design fabrication services. We also design and manufacture a variety of custom subsea equipment, such as riser flotation tank systems, guide bases, running tools and manifolds. In addition, we also offer blow-out preventer and drilling riser testing and repair services. These assembly and testing services are offered through our Houston, Texas, U.K., Singapore and Brazil locations.

Consumable Downhole Products. Shale gas exploration has expanded the need for more advanced completion tools. To reduce well completion cost, the time to drill out tools is very important. We have leveraged our knowledge of molded thermoset composites and elastomers to help meet this demand, and as a result, we have seen growth in casing and cementing products, valves, and combination plugs. One example, the molded frac ball market, has grown from a few thousand units in 2009 to nearly five hundred thousand units in 2015. Additional products include:

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Swab Cups - used primarily in well servicing work;

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Rod Guides/Centralizers - used in both drilling and production for pipe protection;

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Gate Valve and Butterfly Valve Seats – we service many markets in the valve industry including well completion, refining, and distribution;

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Casing and Cementing products – we are a leading custom manufacturer of cementing plugs, well bore wipers, valve assemblies, combination plugs, specialty seals and gaskets;

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Service Tools – our products include frac balls, packer elements, zonal isolation tools, as well as many custom molded products used in the well servicing industry.

We have also had success in developing and producing composite drillable zonal isolation tools (i.e., bridge / frac plugs) utilizing design and production techniques to reduce cost while still delivering high quality products. Time to drill out has been reduced significantly in comparison to other filament wound products in the market.

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

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

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metal-elastomeric FlexJoint^® bearings used in a variety of naval and marine applications; and

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

Backlog. Backlog in our offshore products segment was $340 million at December 31, 2015, compared to $490 million at December 31, 2014 and $580 million at December 31, 2013. We expect approximately 80% of our backlog at December 31, 2015 to be recognized as revenue during 2016. Our offshore products backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. In some instances, these purchase orders are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. While backlog cancellations have not been significant in the past, we incurred cancellations totaling $21.1 million during 2015 ($3.4 million occurring in the fourth quarter of 2015), which we believe is attributable to lower commodity prices and the resultant decrease in capital spending by our clients, and 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.

Regions of Operations

Our offshore products segment provides products and services to customers in the major offshore oil and natural gas producing regions of the world, including the Gulf of Mexico, West Africa, Azerbaijan, the North Sea, Brazil, Southeast Asia, India and Australia.

Customers and Competitors

We market our products and services to a broad customer base, including direct end users, engineering and design companies, prime contractors, and at times, our competitors through outsourcing arrangements. Our largest customers in this segment in 2015 were Halliburton Company, Hess Corporation and Saipem S.p.A. Our main competitors include Cameron International Corporation, FMC Technologies, Inc., Dril-Quip, Inc., National Oilwell Varco, Inc., GE Oil & Gas (a division of General Electric Company) and Liebherr Cranes, Inc.

Well Site Services

Overview

During the year ended December 31, 2015, we generated approximately 34% of our revenue and 26% of our gross margin from our well site services segment. Our well site services segment includes a broad range of products and services that are used to drill for, establish and maintain the flow of oil and natural gas from a well throughout its life cycle. In this segment, our operations primarily include completion-focused equipment and services as well as land drilling services. We use our fleet of completion tools and drilling rigs to serve our customers at well sites and project development locations. Our products and services are used both in onshore and offshore applications throughout the drilling, completion and production phases of a well's life cycle.

Well Site Services Market

Demand for our completion services 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 natural gas. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices.

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Services

Completion Services. Our completion services business, which is primarily marketed through the brand names Oil States Energy Services, Tempress, Stinger Wellhead Protection and Quality International, provides a wide range of services for use in the onshore and offshore oil and gas industry, including:

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wellhead isolation services;

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wireline and coiled tubing support services;

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frac valve and flowback services;

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well testing, including separators and line heaters;

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ball launching services;

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downhole extended-reach technology;

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pipe recovery systems;

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thru-tubing milling and fishing services;

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hydraulic chokes and manifolds;

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blow out preventers; and

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gravel pack and sand control operations on well bores.

Employees in our completion services business typically rig up and operate our equipment on the well site for our customers. Our completion services equipment is primarily used during the completion and production stages of a well. As of December 31, 2015, we provided completion services at approximately 43 distribution points throughout the United States, Canada, Mexico and Argentina. We continue to consolidate operations in areas where our product lines previously had separate facilities and have closed facilities in areas where operations are marginal in order to streamline operations and enhance our facilities to improve operational efficiency. We typically provide our services and equipment based on daily rates which vary depending on the type of equipment and the length of the job. Billings to our customers typically separate charges for our equipment from charges for our field technicians. We own patents or have patents pending covering some of our technology, particularly in our wellhead isolation equipment and downhole extended-reach technology product lines. Our customers in the completion services business include major, independent and private oil and gas companies and other large oilfield service companies. Our largest customers in this segment in 2015 were Anadarko Petroleum Corporation, Devon Energy Corporation and Noble Energy Incorporated. 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, is located in the United States and provides land drilling services 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, 2015, we had a total of thirty-four semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds, fifteen of which were fabricated and/or assembled in our Odessa, Texas facility during the last ten years with components purchased from specialty vendors. Twenty-four of these drilling rigs are based in the Permian Basin and ten are based in the Rocky Mountain region. Utilization of our drilling rigs decreased from an average of 87% in 2014 to an average of 33% in 2015 due to lower crude oil prices and, on December 31, 2015, only five of our rigs, or 15%, were working or under contract. We believe that we may experience additional reductions in the utilization of our drilling rigs if commodity prices do not improve or decline further.

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. Our largest drilling services customers in 2015 were Energen Resources Corporation (representing 26% of our drilling services revenues in 2015), Apache Corporation and Crescent Point Energy US Corporation. The land drilling business is highly fragmented, and our competition consists of a small number of larger companies and many smaller companies. Our Permian Basin drilling activities target primarily oil reservoirs while our Rocky Mountain drilling activities target oil, liquids-rich and natural gas reservoirs.

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Seasonality of Operations

Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in 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. The spring thaw in these regions restricts operations in the second quarter of our fiscal year and adversely affects our operations and our ability to provide services. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

Employees

As of December 31, 2015, the Company employed 3,586 full-time employees on a consolidated basis, 42% of whom are in our well site services segment, 56% of whom are in our offshore products segment and 2% of whom are in our corporate headquarters. We were party to collective bargaining agreements covering approximately 27 employees located in Argentina and the United Kingdom as of December 31, 2015. We believe we have good labor relations with our employees.

Government Regulation

Our business is significantly affected by foreign and domestic laws and regulations at the federal, provincial, state and local levels relating to the oil and natural gas industry, worker safety and environmental protection. To the extent that these laws and regulations impose more stringent requirements or increased costs or delays upon our customers in the performance of their operations, the resulting demand for our products and services by those customers may be adversely affected, which impact could be significant and long-lasting. Moreover, changes in these laws and regulations, including the implementation of more restrictive standards and increased levels of enforcement, could significantly affect our business. We cannot predict changes in the level of enforcement or interpretation of existing laws and regulations or the effect changes in these laws and regulations may have on us or our future operations or earnings. We also are not able to predict the extent to which new laws and regulations will be adopted or whether such new laws and regulations may impose more stringent or costly restrictions on our operations.

We depend on the demand for our products and services from oil and natural gas exploration and production companies. This demand is affected by changing taxes, price controls and laws and regulations relating to the oil and natural gas industry generally, including those specifically directed to oilfield and offshore operations. The adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas in areas where we operate could also adversely affect our operations by limiting demand for our products and services. We cannot determine the extent to which our future operations and earnings may be affected by new legislation or regulations or amendments of existing laws or regulations.

Our operations and the operations of our customers for whom we provide our products and services are subject to numerous stringent and comprehensive foreign, federal, provincial, state and local environmental laws and regulations governing the release or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring us or our customers to conduct difficult and costly actions to achieve and maintain compliance. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution.

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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. Moreover, it is possible that other developments, such as the adoption of new, more stringent environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities upon us or our customers that we cannot currently quantify.

With regard to our operations in the United States, we generate wastes, including non-hazardous and hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. With authority delegated from the United States Environmental Protection Agency, or “EPA,” most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA. These wastes, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain of these oil and natural gas exploration and production wastes now classified as non-hazardous could be re-classified as hazardous in the future. For example, in August 2015, several non-governmental organizations filed notice of intent to sue the EPA under RCRA for, among other things, the agency’s alleged failure to reconsider whether such exclusion should continue to apply. Any such re-classification of these currently exempt wastes to hazardous could subject our oil and natural gas exploration and production customers to more rigorous and costly operating and disposal requirements, which could reduce demand for the products and services we provide and result in a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes.

Also in connection with our operations in the United States, the federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the "Superfund" law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that transported, disposed of, or arranged for the transport or disposal of the hazardous substances at the site where the release occurred. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently have operations in the United States on properties where activities involving the handling of hazardous substances or wastes have been conducted by previous owners or operators whose operations were not under our control. These properties may be subject to CERCLA, RCRA and analogous state laws. Under these laws and related regulations, we could be required to remove or remediate previously discarded hazardous substances and wastes or property contamination that was caused by these third parties.

In the course of our operations in the United States, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or "NORM." NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the domestic properties upon which we operate have been used for oil and natural gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.

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Our operations in the United States are also subject to the Federal Water Pollution Control Act, as amended, or CWA, and analogous state laws that impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited unless the discharge is permitted by the EPA or applicable state agencies. The EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the CWA over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the rule expands the scope of the CWA’s jurisdiction, we or our customers could face increased costs and delays with respect to obtaining permits for certain activities in wetland areas.

Many of the domestic properties upon which we operate require permits for discharges of wastewater and/or storm water, and we have developed a system for securing and maintaining these permits, where required. In addition, the Oil Pollution Act of 1990, as amended, or OPA, imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party under OPA includes the owner or operator of an onshore facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The CWA and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, require the development and implementation of spill prevention and response plans and impose potential liability for the remedial costs and associated damages arising out of any unauthorized discharges.

A certain portion of our completion services business supports other contractors performing hydraulic fracturing to enhance the production of natural gas from formations with low permeability, such as shales. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA issued Clean Air Act final regulations in 2012 and proposed additional Clean Air Act regulations in August 2015 governing performance standards for the oil and natural-gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural-gas extraction operations must meet before discharging to a treatment plant; and issued in 2014 a prepublication of its 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, or BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands although, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups. 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. States could elect to prohibit hydraulic fracturing altogether, following the lead of the State of New York in 2015. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state or local legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, any or all of which could reduce demand for our completion services business.

In addition, certain governmental reviews in the United States are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015. That report concluded that hydraulic fracturing activities have not lead to widespread, systemic impacts on drinking water sources in the United States, although it identified above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies, depending on the results obtained, could spur initiatives to further regulate hydraulic fracturing, which events could delay or curtail production of oil and natural gas by exploration and production operations, some of which are performed by our customers, and thus reduce demand for our North American completion products and services.

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In response to the Deepwater Horizon drilling rig explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010, the Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE, each agencies of the U.S. Department of the Interior, or DOI, 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 restrictions by offshore exploration, development and production operators, some of whom are our customers, in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans and possible additional regulatory initiatives could adversely affect or delay new drilling and ongoing development efforts, which could have a material adverse impact on our and our customers’ businesses. Moreover, new regulatory initiatives may be adopted or enforced by the BOEM and/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 2015, the BSEE issued a notice of proposed rulemaking, expected to be finalized in 2016, that focuses on well blowout preventer systems and well control with respect to operations on the Outer Continental Shelf. The proposed rule requires, among other things, incorporation of the latest industry standards establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers, as well as more controls over the maintenance and repair of blowout preventers. In a second example, in September 2015, the BOEM issued draft guidance that would bolster supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines and other facilities. Among other things, this draft guidance proposes to eliminate the “waiver” exemption currently allowed by the BOEM with respect to offshore supplemental bonding in favor of a self-insurance mechanism that would allow more operators on the Outer Continental Shelf to seek self-insurance for a portion of their supplemental bonding obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. The BOEM is expected to issue the draft guidance in the form of a final Notice to Lessees and Operators by no later than early summer 2016. If our customers are unable to obtain the additional required supplemental bonds or other financial assurances as directed by BOEM, the BOEM could impose monetary penalties or require the operations of those customers on federal leases to be suspended or cancelled.

These recent or any new rules, regulations or legal initiatives could delay or disrupt our customer’s 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 them to incur penalties, fines, or shut-in production at one or more of their facilities, which developments 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 similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and 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.

Some of our operations as well as those of our oil and natural gas customers in the U.S. also result in emissions of regulated air pollutants. The federal Clean Air Act, as amended, or CAA, and analogous state laws require permits for facilities in the United States that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, amendment of the CAA or comparable state laws may cause our oil and natural gas exploration and production customers to incur capital expenditures for installation of air pollution control equipment and to encounter construction delays while applying for and receiving new or amended permits, which could have an adverse effect on demand for our products and services. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (NAAQS) for ground-level ozone from the current standard of 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. Certain areas of the country currently in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult for us or our exploration, development and production customers to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our or our customers’ operations. Compliance with this final rule could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our or our customers’ equipment, result in longer permitting timelines, and significantly increase our or our customers’ capital expenditures and operating costs, which could adversely impact our and our customers’ businesses.

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Past scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or GHG, and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen. The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations is currently uncertain. Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 per cent reduction from 2005 levels by 2020, and the Canadian federal government has also indicated objectives of reducing overall Canadian GHG emissions by 30% from 2005 levels by 2030 and by 60% to 70% from 2006 levels by 2050. One measure the government of Canada has undertaken in pursuit of this objective is to regulate GHG emissions on a sector by sector basis. The oil and gas sector has yet to be subject to specific emission targets at the federal level although, in May 2015, the federal government announced its intention to develop new regulatory measures for the oil, gas and chemical industries. However, as discussed below, such emissions targets are being proposed in Alberta. If and to the extent such specific emission targets are established, the costs of complying with such emission targets may adversely affect our and our clients' levels of activity in the energy sector and our respective financial results.

Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets, and a company can meet the applicable emissions limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” by making payments of $15 per ton of carbon-dioxide equivalent emissions to the Alberta Climate Change and Management Fund. The Specified Gas Reporting Regulation imposes GHG emissions reporting requirements if certain established facilities have GHG emissions of 100,000 tons or more of carbon dioxide equivalent in a calendar year. However, in November 2015, Alberta Premier Rachel Notley announced that the province will transition from the current approach to an oil sands-based performance standard for carbon pricing and will legislate an overall limit to oil sands GHG emissions. In particular, Alberta will implement a $20 per ton carbon tax in January 2017 that will increase to $30 per ton carbon tax in January 2018 that will be applied to oil sands facilities emitting GHGs as a means of reducing GHG emissions. Moreover, Alberta plans to restrict GHG emissions from oil sands operations by introducing an emissions limit of 100 megatons of carbon per year; data reported by the Alberta government indicates that oil sands operations currently generate approximately 70 megatons of carbon a year. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in permits and under other environmental regulations. The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. The direct and indirect costs of overlapping regulations may adversely affect our operations and financial results as well as those of our customers with whom we conduct business.

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In the United States, the EPA has determined that emissions of GHGs present an endangerment to public health and the environment and, based on those findings, adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by the states. These EPA rulemakings could adversely affect our and our exploration, development and production customers’ operations and restrict or delay our ability to obtain air permits for new or modified sources that are major sources of GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from specified large GHG emission sources in the United States, including, among others, offshore and onshore oil and natural gas production facilities.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us or our customers to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas, which could reduce the demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. For example, in August 2015, the EPA proposed rules that will establish emission standards for methane from certain new and modified oil and natural-gas production and natural-gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural-gas sector by up to 45 percent from 2012 levels by 2025. The EPA’s proposed rule package includes standards to address emissions of methane from equipment and processes across the source category, including hydraulically-fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps. The EPA is expected to finalize these rules in 2016. In addition, on an international level, the United States is one of almost 200 nations (including Canada) that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The federal Endangered Species Act, as amended, or the ESA, restricts activities in the United States that may affect endangered or threatened species or their habitats. If endangered species are located in areas of the United States where our oil and natural gas exploration and production customers operate, such operations could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service, or FWS, is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the end of the agency’s 2017 fiscal year. For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, Colorado and Oklahoma, as a threatened species under the ESA. However, on September 1, 2015, the U.S. District Court for the Western District of Texas vacated the FWS’ rule listing the lesser prairie chicken in its entirety, concluding that the decision to list the species was arbitrary and capricious. It remains to be seen how the FWS responds to the vacating of its rule. The designation of previously unprotected species as threatened or endangered in areas of the United States where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our products and services.

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

Our operations outside of the United States are potentially subject to similar foreign governmental controls relating to protection of the environment. We believe that, to date, our operations outside of the United States have been in substantial compliance with existing requirements of these foreign governmental bodies and that such compliance has not had a material adverse effect on our operations. However, this trend of compliance with existing requirements may not continue in the future or the cost of such compliance may become material. For instance, any future restrictions on emissions of GHGs that are imposed in foreign countries in which we operate, could adversely affect demand for our services.

In addition, some of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under states' workers' compensation laws inapplicable to these employees and permit them or their representatives generally to pursue actions against us for damages or job-related injuries with no limitations on our potential liability.

Item 1A. Risk Factors

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

Demand for most of our products and services is substantially dependent on the levels of expenditures by companies in the oil and natural gas industry. We believe our customers’ capital expenditures will further decline in 2016 and beyond if the current depressed oil and natural gas price environment continues or worsens. This could 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 has continued in 2016 has caused a reduction in most of our customers’ drilling, completion and other production activities and related spending on our products and services in 2015. 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 our services, particularly customers of our well site services segment. These conditions generally worsened throughout 2015 and, if oil and natural gas prices remain depressed or further decline, this further reduction in our customers’ activity levels and spending, and reductions in the prices we charge, could continue and accelerate through 2016 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.

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Should the depressed commodity price environment not improve or decrease further, 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, 2015, we had $122.9 million in borrowings outstanding under the Credit Agreement and $37.7 million of outstanding letters of credit, leaving $439.4 million available to be drawn under the revolving credit facility. However, we expect that we may not be able to access the entire amount available under the credit facility during 2016 and potentially beyond, as we expect our trailing twelve month EBITDA to decline during 2016, limiting the amount we may borrow while remaining in compliance with the total debt to consolidated EBITDA covenant. As more fully disclosed in Note 1, Organization and Basis of Presentation, 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 2016.

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

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the level of drilling activity;

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the level of production;

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the levels of oil and natural gas inventories;

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depletion rates;

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worldwide demand for oil and natural gas;

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

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

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

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

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global weather conditions and natural disasters;

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worldwide economic activity including growth in developing countries;

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

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

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

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rapid technological change and the timing and extent of development of energy sources, including Liquefied Natural Gas (LNG) or alternative fuels;

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environmental and other governmental laws and regulations; and

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domestic and foreign tax policies.

The current oversupply of oil and natural gas relative to demand has resulted in significantly lower oil and natural gas prices. As a result, many of our customers have announced or are expected to announce reductions or delays in their capital spending in 2016, which consequently would reduce the demand for our products and services and exert additional downward pressure on the prices of our products and services. If the current depressed commodity price environment for oil and natural gas continues for a prolonged period, it will likely result in further reductions of capital expenditures by our customers, causing further declines in the demand for, and prices of, our products and services. Any prolonged reduction in the overall level of exploration and production activities, whether resulting from changes in oil and natural gas prices or otherwise, could materially adversely affect our financial condition, results of operations and cash flows in many ways including by negatively affecting:

●

our utilization, revenues, cash flows and profitability;

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our ability to obtain additional capital to finance our business and the cost of that capital; and

●

our ability to attract and retain skilled personnel.

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, which could adversely affect our products and services.

Although we do not directly engage in hydraulic fracturing, a certain portion of our completion services business supports 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. Due to concerns raised regarding potential impacts of hydraulic fracturing and fracturing fluids disposal on drinking water and groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated in the United States to render permitting, public disclosure and construction and operational compliance requirements for our customers more stringent for hydraulic fracturing. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA issued CAA final regulations in 2012 and proposed additional CAA regulations in August 2015 governing performance standards for the oil and natural-gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural-gas extraction operations must meet before discharging to a treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups. 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. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular.

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In addition, certain governmental reviews in the United States are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not lead to widespread, systemic impacts on drinking water sources in the United States, although there are above- and below-ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies, depending on the results obtained, could spur initiatives to further regulate hydraulic fracturing, which events could delay or curtail production of oil and natural gas by exploration and production operators, some of which are performed by our customers, and thus reduce demand for our North American completion products and services. In the event that new or more stringent federal, state or local legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, any of which could reduce demand for the products and services of each of our business segments.

Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, oil spill-response and decommissioning plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon explosive incident and resulting oil spill in the United States Gulf of Mexico in 2010, 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 restrictions, in addition to any uncertainties or inconsistencies in current 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 adversely affect or delay new drilling and ongoing development efforts.

Moreover, new regulatory initiatives may be adopted or enforced by the BOEM and/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 2015, the BSEE issued a notice of proposed rulemaking, expected to be finalized in 2016, that focuses on well blowout preventer systems and well control with respect to operations on the Outer Continental Shelf. The proposed rule requires, among other things, incorporation of the latest industry standards establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers, as well as more controls over the maintenance and repair of blowout preventers. In a second example, in September 2015, the BOEM issued draft guidance that would bolster supplemental bonding procedures for the decommissioning of offshore wells, platforms, pipelines and other facilities. Among other things, this draft guidance proposes to eliminate the “waiver” exemption currently allowed by the BOEM with respect to offshore supplemental bonding in favor of a self-insurance mechanism that would allow more operators on the Outer Continental Shelf to seek self-insurance for a portion of their supplemental bonding obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. The BOEM is expected to issue the draft guidance in the form of a final Notice to Lessees and Operators by no later than early summer 2016. If our customers are unable to obtain the additional required supplemental bonds or other financial assurances as directed by BOEM, the BOEM could impose monetary penalties or require the operations of those customers on federal leases to be suspended or cancelled.

These recent, or any new, rules, regulations or legal initiatives could delay or disrupt our customer’s 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 them to incur penalties, fines, or shut-in production at one or more of their facilities, which developments 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 similar to the Deepwater Horizon incident were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and 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.

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

As of December 31, 2015, goodwill represented approximately 16% 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 for each of our reporting units (completion services, drilling services and offshore products) for impairment in value and to recognize a non-cash charge against earnings with a corresponding decrease in stockholders' equity if circumstances, some of which are beyond our control, indicate that the carrying amount will not be recoverable. It is possible that we could recognize goodwill impairment losses in the future if, among other factors:

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global economic conditions deteriorate;

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

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costs of equity or debt capital increase; or

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valuations for comparable public companies or comparable acquisition valuations deteriorate.

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 27% (12% excluding the UK and Canada) of our consolidated revenue in the year ended December 31, 2015. Risks associated with our operations in foreign areas include, but are not limited to:

	●	expropriation, confiscation or nationalization of assets;

	●	renegotiation or nullification of existing contracts;

	●	foreign exchange limitations;

	●	foreign currency fluctuations;

	●	foreign taxation;

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

	●	changing political conditions;

	●	changing foreign and domestic monetary policies;

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

	●	regional economic downturns.

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An illustration of this risk is the current recessionary economic conditions in Brazil which, at present, are having a negative impact on future orders and growth prospects for the Company’s operations in Brazil. Sales to customers in Brazil accounted for approximately 5% of the Company’s consolidated revenues during 2015 and 4% in 2014.

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. With respect to our potential exposure to foreign currency fluctuations and devaluations, for the year ended December 31, 2015, approximately 27% of our revenues originated from subsidiaries outside of the U.S. and were denominated in currencies including, among others, the pound sterling. As a result, a material decrease in the value of these currencies relative to the U.S. dollar may have a negative impact on our reported revenues, net income, and cash flows. Any currency controls implemented by local monetary authorities in countries where we currently operate could also adversely affect our business, financial condition, and results of operations.

We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.

Our operations are significantly affected by stringent foreign, federal, provincial, state, and local laws, and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. We could be exposed to liabilities for cleanup costs, natural resource damages, and other damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though our conduct was lawful at the time it occurred or the conduct resulting in such damage and costs were caused by, prior operators or other third-parties. Environmental laws and regulations are subject to change in the future, possibly resulting in more stringent legal requirements. If existing regulatory requirements or enforcement policies change, we may be required to make significant, unanticipated capital and operating expenditures.

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Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:

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issuance of administrative, civil, and/or criminal penalties;

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denial or revocation of permits or other authorizations;

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reduction or cessation in operations; and

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

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

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

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

Climate change continues to receive increasing attention from the general public, the scientific community, and governments, both in the United States and in foreign countries. The debate is ongoing as to the extent to which our climate is changing, the potential causes of any change and its potential impacts. Some attribute global warming to increased levels of GHGs, including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit GHG emissions. Among other regulatory efforts, significant focus is being made on companies that are active producers of depleting natural resources.

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

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result in increased costs associated with our operations and our customers' operations;

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

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reduce the demand for carbon-based fuels; and

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reduce the demand for our products and services.

Any adoption of these or similar proposals by foreign or domestic federal, regional, or state governments, mandating a substantial reduction in GHG emissions, or imposing a carbon tax on emission of GHGs, could have far-reaching and significant impacts on the energy industry. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions, would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our products and services. See "Part I, Item 1. “Business - Government Regulation" for a more detailed description of our climate change-related risks.

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

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

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cap and trade system for emissions;

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increased supplemental bonding limits on exploration and production decommissioning activities;

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repeal of expensing of intangible drilling costs and exploration and development costs;

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

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repeal of percentage depletion;

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

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

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

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repeal of the deduction for tertiary injectants;

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changes to the tax treatment of Master Limited Partnerships (MLPs); and

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changes to the foreign tax credit limitation calculation.

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. A portion of our completion services operations in Canada are conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the spring months and, as a result, adversely affects our operations and our ability to provide products and services in the second and, to a lesser extent, third quarters of our fiscal year. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters.

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

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

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Our inability to control the inherent risks of identifying and integrating businesses that we may acquire, including any related increases in debt or issuances of equity securities, could adversely affect our operations.

Acquisitions have been, and our management believes will continue to be, a key element of our growth strategy. 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:

	●	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.

Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and shareholders of the Company may not have the opportunity to evaluate the economic, financial, and other relevant information that we will consider in evaluating future acquisitions.

We may not have adequate insurance for potential liabilities and our insurance may not cover certain liabilities, including litigation risks.

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.

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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:

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

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

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

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

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure, or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. 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. 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.

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

We depend on several significant customers in each of our business segments. For a more detailed explanation of our customers for each of our business segments, see “Item 1. Business.” The loss of any one of our largest customers in any of our business segments, or a sustained decrease in demand by any of such customers, could result in a substantial loss of revenues and could have a material adverse effect on our results of operations. In addition, the concentration of customers in one industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. While we perform ongoing credit evaluations of our customers, we do not generally require collateral in support of our trade receivables.

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As a result of our customer concentration, risks of nonpayment and nonperformance by our counterparties are a concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Many of our customers finance their activities through cash flow from operations, the incurrence of debt, or the issuance of equity. Many of our customers are experiencing 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. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The inability, or failure of, our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

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

The market price of common stock of companies engaged in the oil and 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. In addition, some customer contracts stipulate consequential damages payable, generally as a result of our gross negligence or willful misconduct. The final delivered products may also include customer and third-party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.

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

As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs, and any gross profit realized on these fixed-price contracts, may vary from the initially expected contract economics. There is inherent risk in the estimation process including significant unforeseen technical and logistical challenges, or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices (including the price of steel) through increased pricing.

In fulfilling some contracts, we provide limited warranties for our products. Although we estimate and record a provision for potential warranty claims, repair or replacement costs under warranty provisions in our contracts could exceed the estimated cost to cure the claim, which could be material to our financial results. We utilize percentage-of-completion accounting, depending on the size and length of a project, and variations from estimated contract performance could have a significant impact on our reported operating results as we progress toward completion of major jobs.

Backlog in our offshore products segment is subject to unexpected adjustments and cancellations and is, therefore, an imperfect indicator of our future revenues and earnings.

The revenues projected in our offshore products segment backlog may not be realized or, if realized, may not result in profits. Because of potential changes in the scope or schedule of our customers’ projects, we cannot predict with certainty when or if backlog will be realized. In addition, even where a project proceeds as scheduled, it is possible that contracted parties may default and fail to pay amounts owed to us. Material delays, cancellations or payment defaults could materially affect our financial condition, results of operations, and cash flows.

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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 ($3.4 million occurring in the fourth quarter of 2015) and our backlog in our offshore products segment decreased to $340 million at December 31, 2015, from $490 million at December 31, 2014, and $580 million at December 31, 2013, which we believe is attributable to lower commodity prices and the resultant decrease in capital spending by our clients. If commodity prices do not improve, we may incur additional cancellations or declines in our backlog during 2016. If we experience significant project terminations, suspensions, or scope adjustments, to contracts included in our backlog, our financial condition, results of operations, and cash flows, may be adversely impacted.

We might be unable to employ a sufficient number of technical personnel.

Many of the products that we sell, especially in our offshore products segment, are complex and highly engineered, and often must perform in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize, and enhance these products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. During periods of increased activity, the demand for skilled workers is high, and the supply is limited. 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 business segments, 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 several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services, and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services, or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, and results of operations.

If we do not develop new competitive technologies and products, our business and revenues may be adversely affected.

The market for our offshore products is characterized by continual technological developments to provide better performance in increasingly greater water depths, higher pressure levels and harsher conditions. If we are unable to design, develop, and produce commercially, competitive products in a timely manner in response to changes in technology, our business and revenues will be adversely affected. In addition, competitors or customers may develop new technologies, which address similar or improved solutions to our existing technology. 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, particularly in offshore products or in our completion services business, 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.

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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, in particular during times of strong demand, or an increase in the cost of such materials, 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.

Our operations may suffer due to increased industry-wide capacity of certain types of equipment or assets.

The demand for and pricing of certain types of our assets and equipment, particularly our drilling rigs and completion services assets, is subject to the overall availability of such assets in the marketplace. If demand for our assets were to decrease, or to the extent that we and our competitors increase our capacity in excess of current demand, we may encounter decreased pricing for, or utilization of, our assets and services, which could adversely impact our operations and profits.

We might be unable to protect our intellectual property rights.

We rely on a variety of intellectual property rights that we use in our offshore products and completion services businesses, particularly our patents relating to our FlexJoint^® and Merlin™ technology and intervention and downhole extended-reach tools (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.

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

We depend on the continued employment and performance of key members of our management. If any of our key managers resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain "key man" life insurance for any of our officers.

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Employee and customer labor problems could adversely affect us.

As of December 31, 2015, we are party to collective bargaining agreements covering 20 employees in Argentina and 7 employees in the United Kingdom. We have not experienced strikes, work stoppages or other slowdowns in the past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business, financial condition and results of operations.

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

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

The Spin-Off of Civeo may subject us to future liabilities.

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.

If the Spin-Off, or certain internal transactions undertaken in anticipation of the Spin-Off, were determined to be taxable for U.S. federal income tax purposes, then we and our stockholders could be subject to significant tax liability.

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.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

Location	Approximate Square Footage/ Acreage	Description
United States:
Houston, Texas (lease)	30,931	Principal executive offices
Arlington, Texas (own and lease)	41 acres	Various contiguous offices, manufacturing and warehouse facilities located in fourteen buildings
Houston, Texas	25 acres	Offshore products office, manufacturing facility and yard
Houston, Texas	22 acres	Offshore products manufacturing facility and yard
Houston, Texas (lease)	112,312	Offshore products service facility and office
Houston, Texas	67,000	Offshore products service facility and office
Houston, Texas (lease)	50,750	Offshore products service facility and office
Houma, Louisiana	40 acres	Offshore products manufacturing facility and yard
Tulsa, Oklahoma	74,600	Offshore products molding facility
Tulsa, Oklahoma (lease)	71,800	Offshore products molding facility
Oklahoma City, Oklahoma	123,000	Offshore products service facility and office
Lampasas, Texas	48,500	Offshore products molding facility
Lampasas, Texas (lease)	20,000	Offshore products warehouse
Houston, Texas (lease)	23,441	Completion services office
Alice, Texas	27 acres	Completion services office and warehouse
New Iberia, Louisiana	10 acres	Completion services shop
Houma, Louisiana	10 acres	Completion services office and warehouse
Rock Springs, Wyoming	10 acres	Completion services shop
Williston, North Dakota	8 acres	Completion services shop
Renton, Washington (lease)	12,750	Completion services office and shop
Odessa, Texas	21 acres	Drilling services office, shop, warehouse and yard
Casper, Wyoming	7 acres	Drilling services office, shop and yard

International:
Rio de Janeiro, Brazil	31 acres	Offshore products manufacturing facility and yard
Macaé, Brazil	17 acres	Offshore products manufacturing facility and yard
Macaé, Brazil (lease)	6 acres	Offshore products manufacturing facility and yard
West Lothian, Scotland	27 acres	Offshore products manufacturing facility and yard
Aberdeen, Scotland (lease)	15 acres	Offshore products manufacturing facility and yard
Bathgate, Scotland	3 acres	Offshore products manufacturing facility and yard
Rayong, Thailand	11 acres	Offshore products manufacturing and service facility
Singapore (lease)	237,621	Offshore products manufacturing facility
Barrow-in-Furness, England (own and lease)	63,300	Offshore products service facility and yard
Navi Mumbai, India	3 acres	Offshore products manufacturing facility
Navi Mumbai, India (lease)	1 acres	Offshore products manufacturing facility
Red Deer, Alberta, Canada	4 acres	Completion services office and shop
Grand Prairie, Alberta, Canada	4 acres	Completion services office and shop
Villahermosa, Mexico (lease)	34,400	Completion services shop and yard
Neuquén, Argentina (lease)	14,262	Completion services shop and yard
Cutral Có, Argentina (lease)	5,380	Completion services shop and yard

We have a total of 43 completion services locations throughout the United States and in Canada, Mexico and Argentina. Most of these office locations are leased and provide sales, technical support and personnel services to our customers. We also have various offices supporting our business segments which are both owned and leased. We believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing additional suitable space upon expiration of our current lease terms.

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Item 3. Legal Proceedings

In the ordinary course of conducting our business, we become involved in litigation and other claims from private party actions, as well as judicial and administrative proceedings involving governmental authorities at the federal, state and local levels. During 2014 and early 2015, a number of lawsuits were filed by current and former employees, in Federal Court against the Company and or one of its subsidiaries, alleging violations of the Fair Labor Standards Act (“FLSA”). The plaintiffs seek damages and penalties for the Company’s alleged failure to: properly classify its field service employees as “non-exempt” under the FLSA; and pay them on an hourly basis (including overtime). The plaintiffs are seeking recovery on their own behalf as well as a class of similarly situated employees. Settlement of the class action against the Company was approved and a judgment was entered November 19, 2015. The Company has settled the vast majority of these claims and is evaluating potential settlements for the remaining individual plaintiffs’ claims which are not expected to be significant.

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

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Common Stock Information

Our authorized common stock consists of 200,000,000 shares of common stock. There were 51,449,961 shares of common stock outstanding as of February 18, 2016. The approximate number of record holders of our common stock as of February 18, 2016 was 21. Our common stock is traded on the New York Stock Exchange under the ticker symbol OIS. The closing price of our common stock on February 18, 2016 was $25.09 per share.

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

	Sales Price
	High		Low
Pre-Spin-Off
2014
First Quarter	$	104.91	$	90.62
Second Quarter		108.05		94.06

Post-Spin-Off
2014
Second Quarter⁽¹⁾	$	65.77	$	60.80
Third Quarter		65.05		59.66
Fourth Quarter		62.34		41.51
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

(1)

On May 30, 2014, we completed the spin-off of our accommodations business. The May 30, 2014, closing price of our common stock on the NYSE was $107.58. On June 2, 2014, the first trading day following such spin-off, the opening price of our common stock on the NYSE was $60.88.

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.

PERFORMANCE GRAPH

The following performance graph and chart compare the cumulative 5-year total stockholder return on the Company's common stock relative to the cumulative total returns of the Standard & Poor's 500 Stock Index, the Philadelphia OSX Index, an index of oil and gas related companies that represent an industry composite of the Company's peer group, and two customized peer groups of thirteen companies and sixteen companies, respectively, whose individual companies are listed in footnotes (1) and (2) below for the period from December 31, 2010 to December 31, 2015. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2010 and assume the reinvestment of all dividends.

(1)

The thirteen companies included in the Company's first customized peer group (Old Peer Group) are: Archrock Inc., Carbo Ceramics Inc., Core Laboratories, Dril-Quip Inc., Forum Energy Technologies Inc., Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.

(2)

The sixteen companies included in the Company's second customized peer group (New Peer Group) are: Archrock Inc., Bristow Group Inc., Carbo Ceramics Inc., Core Laboratories, Dril-Quip Inc., Forum Energy Technologies Inc., Franks International NV, Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., Patterson UTI Energy Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.

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Oil States International – NYSE

	Cumulative Total Return
	12/10		12/11		12/12		12/13		12/14		12/15
OIL STATES INTERNATIONAL, INC.	$	100.00	$	119.16	$	111.62	$	158.71	$	133.55	$	74.42
S & P 500		100.00		102.11		118.45		156.82		178.29		180.75
PHLX OIL SERVICE SECTOR (OSX)		100.00		85.62		87.44		114.50		96.36		74.08
OLD PEER GROUP		100.00		100.90		98.28		139.35		97.56		68.06
NEW PEER GROUP		100.00		100.31		98.22		138.97		97.52		69.69

*$100 invested on December 31, 2010 in stock or index, including reinvestment of dividends. Fiscal year ending December 31st.

(1)

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

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

(3)	Prepared by Research Data Group, Inc. Used with permission. Copyright© 2016. All rights reserved. (www.researchdatagroup.com/S&P.htm).

Unregistered Sales of Equity Securities and Use of Proceeds

None.

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Purchases of Equity Securities by the Issuer and Affiliated Purchases

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs ⁽¹⁾
October 1, 2015 – October 31, 2015	393⁽²⁾	$ 27.47⁽³⁾	--	$ 136,827,937
November 1, 2015 – November 30, 2015	175⁽⁴⁾	$ 32.68⁽⁵⁾	--	$ 136,827,937
December 1, 2015 - December 31, 2015	797⁽⁶⁾	$ 30.22⁽⁷⁾	--	$ 136,827,937
Total	1,365	$ 29.74	--	$ 136,827,937

⁽¹⁾

^{On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization. On September 6, 2013, we announced an increase in the program from $200,000,000 to $500,000,000.}^{On July 29, 2015, the Company’s Board of Directors approved the termination of our existing share repurchase program and authorized a new program providing for the repurchase of up to $150,000,000 of the Company’s common stock. The new program is set to expire on July 29, 2016.}

⁽²⁾

^{Includes 393 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.}

⁽³⁾

^{The price paid per share was based on the closing price of our Company’s common stock on October 1, 2015, October 4, 2015 and October 31, 2015 which represents the dates the restrictions lapsed on such shares.}

⁽⁴⁾

^{Includes 175 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.}

⁽⁵⁾

^{The price paid per share was based on the closing price of our Company’s common stock on November 3, 2015 which represents the date the restrictions lapsed on such shares.}

⁽⁶⁾

^{Includes 797 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.}

⁽⁷⁾

^{The price paid per share was based on the closing price of our Company’s common stock on December 6, 2015 which represents the dates the restrictions lapsed on such shares.}

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Item 6. Selected Financial Data

The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2015. 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 as discontinued operations.

Selected Financial Data

(In thousands, except per share amounts)

	Year Ended December 31,
	2015			2014			2013			2012			2011

Statement of Income Data:
Revenues	$	1,099,977		$	1,819,609		$	1,629,134		$	1,517,720		$	1,239,662
Costs and Expenses:
Product costs, service and other costs		785,698			1,205,884			1,113,168			1,053,646			851,070
Selling, general and administrative expenses		132,664			169,432			150,967			125,290			114,006
Depreciation and amortization expense		131,257			124,776			109,231			88,745			75,684
Other operating (income) expense, net		(4,648	)		9,262			8,491			2,394			709
		1,044,971			1,509,354			1,381,857			1,270,075			1,041,469
Operating income		55,006			310,255			247,277			247,645			198,193
Interest expense, net of capitalized interest		(6,427	)		(17,173	)		(38,830	)		(40,373	)		(37,768	)
Interest income		543			560			628			405			305
Loss on extinguishment of debt⁽¹⁾		--			(100,380	)		(6,168	)		-			-
Other income (expense)		1,446			3,082			1,220			5,415			(152	)
Income from continuing operations before income taxes		50,568			196,344			204,127			213,092			160,578
Income tax provision		(22,197	)		(69,117	)		(75,068	)		(71,947	)		(56,753	)
Net income from continuing operations		28,371			127,227			129,059			141,145			103,825
Net income from discontinued operations, net of tax (including a net gain on disposal of $84,043 in 2013)		226			51,776			292,217			307,482			218,671
Net income		28,597			179,003			421,276			448,627			322,496
Less: Net income attributable to noncontrolling interest		-			-			18			18			43

Net income attributable to Oil States International, Inc.	$	28,597		$	179,003		$	421,258		$	448,609		$	322,453

Net income attributable to Oil States International, Inc.:
Continuing operations	$	28,371		$	127,227		$	129,041		$	141,127		$	103,782
Discontinued operations		226			51,776			292,217			307,482			218,671
Net income attributable to Oil States International, Inc.	$	28,597		$	179,003		$	421,258		$	448,609		$	322,453

Basic net income per share attributable to Oil States International, Inc. common stockholders from:
Continuing operations	$	0.55		$	2.37		$	2.32		$	2.66		$	2.03
Discontinued operations		0.01			0.96			5.26			5.81			4.27
Net income	$	0.56		$	3.33		$	7.58		$	8.47		$	6.30

Diluted net income per share attributable to Oil States International, Inc. common stockholders from:
Continuing operations	$	0.55		$	2.35		$	2.31		$	2.55		$	1.89
Discontinued operations		0.01			0.96			5.22			5.55			3.98
Net income	$	0.56		$	3.31		$	7.53		$	8.10		$	5.86

Weighted average number of common shares outstanding:
Basic		50,269			52,862			54,969			52,959			51,163
Diluted		50,335			53,151			55,327			55,384			55,007

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	Year Ended December 31,
	2015			2014			2013			2012			2011
Other Data:
EBITDA, as defined⁽²⁾	$	187,709		$	438,113		$	357,710		$	341,787		$	273,682
Capital expenditures, including capitalized interest		114,738			199,256			164,895			168,863			130,849
Acquisitions of businesses, net of cash acquired		33,427			157			44,260			80,449			212
Cash used for treasury share repurchases		105,916			226,303			108,535			15,245			12,632
Net cash provided by continuing operating activities		255,768			302,644			235,086			150,960			95,258
Net cash (used in) provided by continuing investing activities, including capital expenditures⁽³⁾		(147,196	)		(198,504	)		393,509			(266,250	)		(134,119	)
Net cash (used in) provided by continuing financing activities		(124,722	)		(378,912	)		(299,928	)		134,309			303,163

	At December 31,
	2015		2014		2013		2012		2011
Balance Sheet Data:
Cash and cash equivalents	$	35,973	$	53,263	$	599,306	$	253,172	$	71,721
Current assets held for sale⁽³⁾		-		-		-		632,496		617,167
Total current assets		611,473		826,666		1,525,907		1,826,092		1,489,659
Property, plant and equipment, net		638,725		649,846		1,902,789		1,827,242		1,534,987
Noncurrent assets held for sale⁽³⁾		-		-		-		31,605		28,232
Total assets		1,599,138		1,809,612		4,131,261		4,439,962		3,703,641
Long-term debt and capital leases, excluding current portion and 2 3/8% Notes		128,554		146,835		972,692		1,279,805		971,621
2 3/8% contingent convertible senior subordinated notes		-		-		-		-		170,884
Total stockholders' equity		1,255,327		1,340,657		2,625,294		2,465,800		1,963,272

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

	Year Ended December 31,
	2015		2014		2013		2012		2011
Net income attributable to Oil States International, Inc. - continuing operations	$	28,371	$	127,227	$	129,041	$	141,127	$	103,782
Depreciation and amortization expense		131,257		124,776		109,231		88,745		75,684
Interest expense, net		5,884		16,613		38,202		39,968		37,463
Loss on extinguishment of debt⁽¹⁾		--		100,380		6,168		-		-
Income tax provision		22,197		69,117		75,068		71,947		56,753
EBITDA, as defined⁽²⁾	$	187,709	$	438,113	$	357,710	$	341,787	$	273,682

(1)

During 2014, we recognized losses on the extinguishment of debt totaling $100.4 million primarily due to the repurchase of our remaining 6 1/2% Notes and 5 1/8% Notes, resulting in a loss of $96.7 million consisting of the premium paid over book value for such notes and the write-off of unamortized deferred financing costs associated with the Notes. We paid a premium to repurchase the 6 1/2% Notes and 5 1/8% Notes due to their fair market value exceeding their book value at the date tendered. In addition, as a result of the refinancing of our bank credit facility in the second quarter of 2014, we recognized a loss of $3.7 million (net of $1.8 million allocated to discontinued operations for the Canadian portion of the revolving credit facility) from the write-off of unamortized deferred financing costs on our revolving credit facility. During 2013, we recognized a loss on the extinguishment of debt totaling $6.2 million from the repurchase of a portion of our 5 1/8% Notes in the fourth quarter of 2013, resulting in a loss of $4.1 million, including the write-off of $0.4 million of unamortized deferred financing costs. Additionally, we wrote off $2.1 million of unamortized deferred financing costs associated with the full repayment of our U.S. term loan.

(2)

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

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(3)	A total of $600 million of cash proceeds was received from the sale of our tubular services business in September 2013. The applicable assets and liabilities of this business have been classified as held for sale in the Consolidated Balance Sheets prior to December 31, 2013.

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 shareholders (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.

Macroeconomic Environment

With the completion of the Spin-Off, we are now a technology-focused, pure-play energy services company. 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 oil and natural gas. 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 expected commodity prices, principally related to crude oil and natural gas.

In the past few years, crude oil prices have been volatile due to global economic uncertainties as well as inadequate regional well site transportation infrastructure. Although this price volatility moderated in 2013 and for the first several months of 2014, significant downward crude oil price volatility began early in the fourth quarter of 2014 and has continued into 2016. Prices dropped precipitously in the fourth quarter of 2014 and into 2015, with a partial recovery during the second quarter of 2015 only to be offset by a decline in prices again in the second half of 2015 which continued into the first quarter of 2016. The material decrease in crude oil prices over this period can primarily be attributed to high levels of global crude oil inventories due to significant production growth in the U.S. shale plays, strengthening of the U.S. dollar relative to other foreign currencies, and the Organization of Petroleum Exporting Companies (OPEC) increasing its production. OPEC has demonstrated an unwillingness to cut its production as it has done in previous years, in an effort to protect market share. These production increases have been offset somewhat by moderate increases in global oil demand. The combination of these factors caused a global supply and demand imbalance for oil and natural gas which, along with concerns regarding the growth outlook in China and the anticipation of potential supply increases related to the lifting of sanctions against Iran, resulted in materially lower crude oil prices in 2015 and to date in 2016. The average price of West Texas Intermediate (WTI) crude oil decreased from an average price of $73 per barrel in the fourth quarter of 2014 to an average of $49 per barrel in 2015. These data points compare to an average price of $93 per barrel in 2014. The average price of Intercontinental Exchange Brent (Brent) crude decreased from an average price of $76 per barrel in the fourth quarter of 2014 to an average of $52 per barrel in 2015. These data points compare to an average price of $99 per barrel in 2014. As of February 18, 2016, WTI crude traded at approximately $31 per barrel while Brent crude traded at approximately $34 per barrel. The magnitude of the supply/demand imbalance has created a market concern that crude oil prices could decline further or remain at their currently low level for the foreseeable future, with the current twelve-month forward strip price for WTI and Brent crude each averaging $37 per barrel. The current and expected price for WTI crude will continue to influence our customers’ spending in U.S. shale play developments, such as the Permian, Bakken, Niobrara, and Eagle Ford basins. Spending in these regions will influence the overall drilling and completion activity in the area and, therefore, the activity of our well site services segment. The price for Brent crude will influence our customers’ spending related to global offshore drilling and development and, thus, the activity of our offshore products segment.

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Given the historical volatility of crude prices, there remains a high degree of risk that prices could deteriorate further due to high levels of domestic and OPEC crude oil production, slowing growth rates in various global regions and/or the potential for ongoing supply/demand imbalances. Conversely, if the global supply of oil were to decrease due to reduced capital investment by our customers or government instability in a major oil-producing nation and energy demand were to continue to increase in the U.S. and countries such as China and India, a recovery in WTI and Brent crude prices could occur. In any event, crude oil price improvements will depend upon a rebalancing of global supply and demand, the timing of which is difficult to predict. If commodity prices do not improve or decline further, demand for our products and services could further decline.

Prices for natural gas in the U.S. averaged $2.62 per mmBtu in 2015 compared to $4.37 per mmBtu in 2014. Natural gas prices declined during 2015 largely due to increased natural gas inventories. Natural gas prices traded at approximately $1.85 per mmBtu as of February 18, 2016. Strong production and a milder winter this year compared to last year resulted in significant increases in natural gas inventories in the U.S. during 2015, from 2% below the 5-year average as of the end of 2014 to 14% above the 5-year average as of the end of 2015. Customer spending in the natural gas shale plays has been limited due to associated gas being produced from unconventional oil wells in North America, specifically onshore shale production resulting from the broad application of horizontal drilling and hydraulic fracturing techniques which continued during 2015, albeit at a much slower pace, and the commissioning of a number of new, large, LNG export facilities around the world. As a result of natural gas production growth outpacing demand growth in the U.S., natural gas prices continue to be weak and are expected to remain below levels considered economical for new investments in numerous natural gas fields, with the current twelve-month forward strip price for natural gas averaging $2.30 per mmBtu. If natural gas production growth continues to surpass demand growth in the U.S. and/or the supply of natural gas were to increase, whether the supply comes from conventional or unconventional production or associated natural gas production from oil wells, prices for natural gas could remain depressed for an extended period and result in fewer rigs drilling for natural gas.

Recent WTI crude, Brent crude and natural gas pricing trends are as follows:

	Average Price ⁽¹⁾
Quarter Ended		WTI Crude (per bbl)		Brent Crude (per bbl)		Henry Hub Natural Gas (per mmBtu)
12/31/2015	$	41.94	$	43.56	$	2.12
9/30/2015		46.49		50.44		2.76
6/30/2015		57.85		61.65		2.75
3/31/2015		48.49		53.98		2.90
12/31/2014⁽²⁾		73.21		76.43		3.78
9/30/2014		97.87		101.90		3.96
6/30/2014		103.35		109.69		4.61
3/31/2014		98.68		108.14		5.18
12/31/2013		97.50		109.23		3.85
9/30/2013		105.83		110.23		3.55

(1)

Source: U.S. Energy Information Administration (EIA). As of February 18, 2016, WTI crude, Brent crude and natural gas traded at approximately $31 per barrel, $34 per barrel and $1.85 per mmBtu, respectively.

(2)

As of December 31, 2014, the price of WTI and Brent crude oil had fallen to $53.45 per barrel and $55.27 per barrel, respectively.

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Overview

Demand for the products and services of our offshore products segment is tied primarily to the long-term outlook for commodity prices. Demand for our well site services segment responds to shorter-term movements in 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 the general global economic environment and regulatory changes in the U.S. 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 drilling market. Sales of our offshore products and services depend primarily upon 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. In this segment, we are particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for 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 using relatively conservative crude oil and natural gas pricing assumptions. We believe some of these deepwater projects 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 continued declines in crude oil prices that have persisted since late 2014 and the uncertain outlook around longer-term pricing improvements have caused exploration and production companies to reevaluate their future capital expenditures in regards to these deepwater projects given that, certain of these deep water projects, may become uneconomical relative to the risk involved. In addition, shorter-cycle product sales (such as elastomer products) and services for this segment have declined in 2015.

In our well site services business segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our completion services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the completion services business is dependent primarily upon the level and complexity of drilling, completion and workover activity throughout North America. Well complexity has increased with the continuing transition to multi-well pads and the drilling of longer laterals along with the increased number of frac stages completed in horizontal wells. Demand for our drilling services 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 Rocky Mountain area in the U.S., 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.

	As Of February 12,	Average Rig Count for Year Ended December 31,
	2016	2015		2014		2013		2012		2011
U.S. Land – Oil	419		723		1,486		1,334		1,335		966
U.S. Land - Natural gas and other	97		219		319		371		537		877
U.S. Offshore	25		35		57		56		47		32
Total U.S.	541		977		1,862		1,761		1,919		1,875
Canada	222		193		380		355		365		423
Total North America	763		1,170		2,242		2,116		2,284		2,298

The average North American rig count for the year ended December 31, 2015 decreased precipitously by 1,072 rigs, or 48.0%, compared to the average for the year ended December 31, 2014 in response to much lower crude oil prices from the levels experienced in 2014. The North American rig count as of February 12, 2016 was 763 rigs, down 60% from the peak level of 1,930 rigs in the fourth quarter of 2014.

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Exacerbating the steep declines in drilling activity, many of our exploration and production customers have been and are continuing to defer 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 is generally driven by the need to preserve cash flow in a weak commodity price environment and/or the desire to produce reserves at a later date with expectations that commodity prices will improve and/or completion costs will continue to decline. Given our well site services segment’s exposure to completion activity, DUCs continue to have a negative impact on our results of operations.

The reduced demand for our products and services coupled with a reduction in the prices we charge our customers, particularly customers of our well site services business segment, have adversely affected our results of operations, cash flows and financial position as of and for the year ended December 31, 2015. If the current pricing environment for oil and natural gas continues, our customers could 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 in 2016. Our customers have experienced a significant decline in their revenues and cash flows due to the commodity price declines experienced with some suffering a significant reduction in liquidity and access to the capital and debt markets. There have already been several exploration and production companies who have declared bankruptcy and others who are forced to sell assets in an effort to preserve liquidity. A continuation of these adverse conditions could affect certain of our customers’ ability to pay or otherwise perform on 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 may 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 our business. Our capital expenditures in 2015 totaled $115 million compared to 2014 capital expenditures of $199 million. Our 2015 capital expenditures included funding to upgrade and maintain our completion services and drilling services equipment, to expand and upgrade our offshore products facilities, and to fund various other capital spending initiatives. We currently expect to spend a total of approximately $50 million to $55 million for capital expenditures during 2016, including approximately $19 million of carry-over from 2015, to upgrade and maintain our offshore products and completion services equipment and to fund various other capital spending projects. Whether planned expenditures will actually be spent in 2016 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 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 an evaluation of both the market outlook and industry fundamentals.

Recent Acquisitions

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 our technology and product offerings. We have made strategic acquisitions in each of our business segments in recent years.

On December 2, 2013, we acquired all of the operating assets of QCS for total cash consideration of $42.3 million. Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. The operations of QCS have been included in our offshore products segment since the acquisition date.

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Consolidated Results of Operations (in millions)

	YEARS ENDED December 31,
								Variance 2015 vs. 2014								Variance 2014 vs. 2013
		2015			2014			$		%			2013			$	%
Revenues
Well site services -
Completion services	$	308.1		$	656.9		$	(348.8	)	(53	)%	$	576.0		$	80.9	14	%
Drilling services		67.8			201.1			(133.3	)	(66	)%		170.5			30.6	18	%
Total well site services		375.9			858.0			(482.1	)	(56	)%		746.5			111.5	15	%
Offshore products		724.1			961.6			(237.5	)	(25	)%		882.6			79.0	9	%
Total	$	1,100.0		$	1,819.6		$	(719.6	)	(40	)%	$	1,629.1		$	190.5	12	%
Product costs; service and other costs (“Cost of sales and service”)
Well site services -
Completion services	$	237.4		$	402.9		$	(165.5	)	(41	)%	$	353.0		$	49.9	14	%
Drilling services		56.3			141.4			(85.1	)	(60	)%		119.5			21.9	18	%
Total well site services		293.7			544.3			(250.6	)	(46	)%		472.5			71.8	15	%
Offshore products		492.0			661.6			(169.6	)	(26	)%		640.7			20.9	3	%
Total	$	785.7		$	1,205.9		$	(420.2	)	(35	)%	$	1,113.2		$	92.7	8	%
Gross margin
Well site services -
Completion services	$	70.7		$	254.0		$	(183.3	)	(72	)%	$	223.0		$	31.0	14	%
Drilling services		11.5			59.7			(48.2	)	(81	)%		51.0			8.7	17	%
Total well site services		82.2			313.7			(231.5	)	(74	)%		274.0			39.7	14	%
Offshore products		232.1			300.0			(67.9	)	(23	)%		241.9			58.1	24	%
Total	$	314.3		$	613.7		$	(299.4	)	(49	)%	$	515.9		$	97.8	19	%
Gross margin as a percentage of revenues
Well site services -
Completion services		23	%		39	%							39	%
Drilling services		17	%		30	%							30	%
Total well site services		22	%		37	%							37	%
Offshore products		32	%		31	%							27	%
Total		29	%		34	%							32	%

YEAR ENDED DECEMBER 31, 2015 COMPARED TO YEAR ENDED DECEMBER 31, 2014

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 foreign jurisdictions, and $3.6 million in tax adjustments primarily related to non-deductible items. Excluding these significant 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 after-tax, and $11.2 million, or $0.14 per diluted share after-tax, 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.

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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 has trended lower during 2015.

Cost of Sales and Service. Our consolidated cost of sales decreased $420.2 million, or 35%, in 2015 compared to 2014 as a result of decreased cost of sales 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 margin 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 sales 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 sales and a $85.1 million, or 60%, decrease in drilling services cost of sales. These decreases in cost of sales, 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 margin as a percentage of revenues decreased from 37% in 2014 to 22% in 2015. Our completion services gross margin 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 margin 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 sales decreased $169.6 million, or 26%, in 2015 compared to 2014 in correlation with the decrease in revenues. Gross margin as a percentage of revenues remained generally constant (31% in 2014 compared to 32% in 2015). The improvement in gross margin 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 have been able to lower our overall cost structure.

Selling, General and Administrative Expenses. Selling, general and administrative (SG&A) 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 exchange gains in 2015.

Operating Income. Consolidated operating income 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.

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.

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Income Tax Expense. 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 foreign 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 for 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 primarily as a result of fluctuations in the foreign currency exchange rates compared to the U.S. dollar for the foreign operations of our reportable segments (primarily in the United Kingdom, Brazil, and Canada). The average exchange rates of the British pound, Brazilian real, and Canadian dollar compared to the U.S. dollar weakened by 5%, 31%, and 16%, respectively, in 2015 compared to 2014.

YEAR ENDED DECEMBER 31, 2014 COMPARED TO YEAR ENDED DECEMBER 31, 2013

We reported net income from continuing operations attributable to the Company for the year ended December 31, 2014 of $127.2 million, or $2.35 per diluted share, including a loss on extinguishment of debt of $100.4 million, or $1.21 per diluted share after-tax, and $11.2 million, or $0.14 per diluted share after-tax, 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. These results compare to net income from continuing operations attributable to the Company of $129.0 million, or $2.31 per diluted share, reported for the year ended December 31, 2013, including $5.7 million, or $0.07 per diluted share after-tax, of transaction costs included in “other operating (income) expense” primarily related to the Spin-Off, a pre-tax loss on the extinguishment of debt of $6.2 million, or $0.07 per diluted share after-tax, and a charge of $3.0 million, or $0.04 per diluted share, from an increase in contingent acquisition consideration in our completion services business. Excluding these significant charges in 2013, net income from continuing operations would have been $138.5 million, or $2.47 per diluted share.

Revenues. Consolidated revenues increased $190.5 million, or 12%, in 2014 compared to 2013.

Our well site services segment revenues increased $111.5 million, or 15%, in 2014 compared to 2013 due to increases in both completion services and drilling services revenues. Our completion services revenues increased $80.9 million, or 14%, in 2014 compared to 2013, primarily due to a 5% increase in the number of service tickets completed and a 9% increase in our revenue per completion services job as a result of increased service intensity in the U.S. shale basins and the Gulf of Mexico. Our drilling services revenues increased $30.6 million, or 18%, in 2014 compared to 2013 primarily as a result of increased utilization of our drilling rigs from an average of 75% during 2013 to an average of 87% in 2014. However, utilization declined beginning in the fourth quarter of 2014 due to lower crude oil prices and, on February 20, 2015, the utilization of our drilling rigs had decreased to 50%.

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Our offshore products segment revenues increased $79.0 million, or 9%, in 2014 compared to 2013. This increase was primarily the result of increased deepwater production facility and subsea product sales, greater elastomer consumable downhole product sales, contributions from the acquisition of QCS, which was acquired in December 2013, and an increase in demand for our services worldwide.

Cost of Sales and Service. Our consolidated cost of sales increased $92.7 million, or 8%, in 2014 compared to 2013 as a result of increased cost of sales at our well site services and offshore products segments of $71.8 million, or 15%, and $20.9 million, or 3%, respectively. With cost of sales and service increasing at a slower rate than our revenues, consolidated gross margin as a percentage of revenues increased from 32% in 2013 to 34% in 2014 primarily due to higher margins realized in our offshore products segment in 2014.

Our well site services segment cost of sales increased $71.8 million, or 15%, in 2014 compared to 2013 as a result of a $49.9 million, or 14%, increase in completion services cost of sales and a $21.9 million, or 18%, increase in drilling services cost of sales. These increases in cost of sales are directly correlated to the revenue increases in these businesses. In our well site services segment, completion services and drilling services gross margins as a percentage of revenues were 37%, 39% and 30%, respectively, in both 2014 and 2013.

Our offshore products segment cost of sales increased $20.9 million, or 3%, in 2014 compared to 2013 and gross margin as a percentage of revenues increased from 27% to 31% primarily due to increased margins realized on our elastomer consumable sales, deepwater production facility and subsea pipeline product sales, as well as improved cost absorption and utilization associated with increased revenue.

Selling, General and Administrative Expenses. (SG&A) expense increased $18.5 million, or 12%, in 2014 compared to 2013. The increase was largely due to increased employee-related costs primarily associated with a 5% increase in total headcount, a portion of which was added in offshore products in connection with the QCS acquisition in December 2013, coupled with increased bad debt expense.

Depreciation and Amortization. Depreciation and amortization expense increased $15.5 million, or 14%, in 2014 compared to 2013 primarily due to capital expenditures made during the previous twelve months across all segments of our Company along with increased depreciation and amortization expense related to the QCS acquisition.

Other Operating (Income) Expense. Other operating (income) expense increased $0.8 million, or 9.1%, in 2014 compared to 2013 primarily due to increased transaction costs incurred in 2014 in connection with the Spin-Off.

Operating Income. Consolidated operating income increased $63.0 million, or 25%, in 2014 compared to 2013 primarily as a result of increases in operating income from our offshore products segment and completion services business of $43.2 million, or 28%, and $21.5 million, or 17%, respectively. These increases in operating income were partially offset by an increase of $5.5 million in transaction costs primarily related to the Spin-Off.

Interest Expense and Interest Income. Net interest expense decreased $21.6 million, or 57%, in 2014 compared to 2013 primarily due to the Company’s repurchase of $34.0 million aggregate principal amount of our 5 1/8% Notes in the fourth quarter of 2013, the 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 and the full repayment of our U.S. term loan in the third quarter of 2013, partially offset by amounts outstanding under our current revolving credit facility coupled with unused commitment fees paid to our lenders. The weighted average interest rate on the Company’s total outstanding debt was 6.0% in 2014 compared to 6.4% in 2013.

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 unamortized deferred financing costs associated with such notes. In addition, as a result of the refinancing of our bank credit facility in the second quarter of 2014, we recognized a loss of $3.7 million (net of $1.8 million allocated to discontinued operations for the Canadian portion of the revolving credit facility) from the write-off of unamortized deferred financing costs on our revolving credit facility. During 2013, we recognized a loss on the extinguishment of debt totaling $6.2 million from the repurchase of a portion of our 5 1/8% Notes in the fourth quarter of 2013, resulting in a loss of $4.1 million, including the write-off of $0.4 million of unamortized deferred financing costs. Additionally, during 2013 we wrote off $2.1 million of unamortized deferred financing costs associated with the full repayment of our U.S. term loan.

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Income Tax Expense. The Company’s income tax provision for 2014 totaled $69.1 million, or 35.2% of pretax income, compared to income tax expense of $75.1 million, or 36.8% of pretax income, for 2013. The decrease in the effective tax rate from the prior year was largely the result of the mix and levels of pre-tax earnings between the Company’s domestic and foreign operations and the loss incurred on extinguishment of debt associated with the debt refinancings completed in connection with the Spin-Off.

Discontinued Operations. Net income from discontinued operations for 2014 was $51.8 million compared to $208.2 million for 2013 (exclusive of a $128.6 million pre-tax gain, $84.0 million after-tax, recorded on the disposal of our tubular services business in 2013.) Revenues reported within discontinued operations were $404.2 million for 2014 compared to $2.1 billion for 2013. Operating income included within discontinued operations was $81.1 million and $305.1 million for 2014 and 2013, respectively. The decreases in revenue and operating income year-over-year primarily relate to the absence of tubular services operations in 2014 compared to 2013 due to this segment’s disposal on September 6, 2013, and the absence of accommodations operations for the months of June through December 2014 compared to a full twelve months in 2013 due to the Spin-Off on May 30, 2014.

Other Comprehensive Income (Loss). Other comprehensive income (loss) increased from a loss of $192.8 million in 2013 to income of less than $1.0 million in 2014 primarily as a result of foreign currency translation adjustments attributable to the accommodations discontinued operations which were spun-off.

Liquidity, Capital Resources and Other Matters

Our primary liquidity needs are to fund operating and capital expenditures, which in the past have included expanding and upgrading our offshore 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. In 2014, we also received a $750 million special cash dividend paid to us by Civeo in connection with the Spin-Off, which was used to refinance debt, and in 2013 we received $600 million from the sale of our tubular services segment. The $750 million dividend received from Civeo was partially offset by $299 million of cash transferred to Civeo in connection with the Spin-Off. 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 and debt offerings.

Operating Activities

Despite the weak market conditions, cash totaling $255.8 million was provided by continuing operations during the year ended December 31, 2015 compared to cash totaling $302.6 million provided by continuing operations during the year ended December 31, 2014. During 2015, $78.2 million was provided from net working capital reductions, primarily due to decreases in receivables partially offset by decreases in accounts payable and accrued liabilities. During 2014, $59.3 million was used to fund working capital, primarily due to increases in receivables in our offshore products segment and completion services business.

Investing Activities

Cash was used in investing activities during the year ended December 31, 2015 in the amount of $147.2 million compared to $198.5 million used during the year ended December 31, 2014. Capital expenditures for continuing operations totaled $114.7 million and $199.3 million during the years ended December 31, 2015 and 2014, respectively. Capital expenditures in both years consisted principally of purchases of completion services equipment, upgrading and maintenance of our drilling services equipment, expansion and upgrading of our offshore products segment facilities and various other capital spending initiatives.

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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 credit facility.

We currently expect to spend a total of approximately $50 million to $55 million for capital expenditures during 2016, including approximately $19 million of carry-over from 2015, to upgrade and maintain our offshore products and completion services equipment and to fund various other capital spending initiatives. Whether planned expenditures will actually be spent in 2016 depends on industry conditions, project approvals and schedules, vendor delivery timing, free flow cash 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 forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company.

At December 31, 2015, we had cash totaling $34.6 million held by foreign subsidiaries, primarily in Singapore, Canada, the United Kingdom and Mexico. Our intent is to utilize at least a portion of these cash balances for future investment outside the United States. Approximately $30 million of cash held by our foreign subsidiaries can be repatriated without triggering any incremental tax consequences. During 2015, we repatriated $35.2 million from our foreign subsidiaries which was used to reduce outstanding borrowings under our credit facility.

Financing Activities

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. Net cash of $378.9 million was used in financing activities during the year ended December 31, 2014, primarily as a result of the repayment of our 6 1/2% and 5 1/8% Notes and repurchases of our common stock, partially offset by net cash received from the Spin-Off (the $750 million special cash dividend received from Civeo) and borrowings under our revolving credit facility.

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 September 6, 2013, the Company announced an increase in its Board-authorized Company stock repurchase program from $200 million to $500 million providing for the repurchase of the Company’s common stock, par value $.01 per share. On July 29, 2015, the Company’s Board of Directors approved the termination of our existing share repurchase program and authorized a new program providing for the repurchase of up to $150 million of the Company’s common stock, par value $.01 per share. The new program is set to expire on July 29, 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. As of December 31, 2015, a total of $456.0 million of our stock (6,902,748 shares, or approximately 13% of the outstanding shares of our common stock at the initiation of our initial share repurchase authorization in August 2012) had been repurchased under these programs. The amount remaining under our current share repurchase authorization as of December 31, 2015 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.

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Credit Facilities. In connection with the Spin-Off, the Company terminated its then existing bank credit facility on May 28, 2014 and entered into a new $600 million senior secured revolving credit facility (the “revolving credit facility”). The Company has an option to increase the maximum borrowings under the new facility to $750 million contingent upon additional lender commitments prior to its maturity on May 28, 2019. The credit facility is governed by a Credit Agreement dated as of May 28, 2014 (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. 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 (as defined in the Credit Agreement). During 2015, our applicable margin over LIBOR was 1.50%. 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. 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 2015.

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, 2015, we were in compliance with our debt covenants and expect to continue to be in compliance during the remainder of 2016. 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.

As of December 31, 2015, we had $122.9 million in borrowings outstanding under the Credit Agreement and $37.7 million of outstanding letters of credit, leaving $439.4 million available to be drawn under the revolving credit facility. However, the total amount available to be drawn under our revolving credit facility is expected to be significantly reduced as our trailing twelve months EBITDA moves lower into 2016 given that, in accordance with the Credit Agreement, total debt cannot exceed 3.25 times our trailing twelve months EBITDA.

Our total debt represented 9.3% of our combined total debt and stockholders’ equity at December 31, 2015 compared to 9.9% at December 31, 2014.

Contractual Obligations. The following summarizes our contractual obligations at December 31, 2015, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):

	Payments due by period
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Contractual obligations
Total debt, including capital leases⁽¹⁾	$	129,087	$	533	$	987	$	123,560	$	4,007
Purchase obligations⁽²⁾		91,362		87,359		4,003		-		-
Non-cancelable operating lease obligations⁽³⁾		26,167		8,271		8,206		3,952		5,738
Total contractual cash obligations	$	246,616	$	96,163	$	13,196	$	127,512	$	9,745

(1)

Excludes interest on variable-rate debt. Since we cannot predict with any certainty the amount of interest due on our revolving debt due to the expected variability of interest rates and principal amounts outstanding, we do not include this in our obligations. If we assume interest payment amounts are calculated using the outstanding principal balances and interest rates as of December 31, 2015 and include applicable commitment fees, estimated interest payments on our variable-rate debt would be $4.9 million “due in less than one year”, $9.8 million “due in one to three years” and $2.0 million “due in three to five years.” 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.

(2)

The purchase obligations of the Company primarily relate to open purchase orders in our offshore products segment.

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(3)

See Note 14 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information.

Our debt obligations at December 31, 2015 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, 2015.

Effects of Inflation

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

Off-Balance Sheet Arrangements

As of December 31, 2015, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.

Tax Matters

Our primary deferred tax assets at December 31, 2015, are related to foreign tax credit carryforwards, employee benefit costs for our Equity Participation Plan and inventory allowance for obsolescence. The foreign tax credit carryforwards will expire in varying amounts after 2021.

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 foreign 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.

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

Critical Accounting Policies

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

Accounting for Contingencies

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

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Tangible and Intangible Assets, including Goodwill

Our goodwill totaled $263.8 million, or 16.5%, of our total assets, as of December 31, 2015. Our other intangible assets totaled $59.4 million, or 3.7%, of our total assets, as of December 31, 2015. 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 2015 review, the carrying values of its asset groups are recoverable, and no impairment losses were recorded. However, the further decline in oil prices subsequent to December 31, 2015 (and the length of that decline) will impact our projected operating cash flows and could potentially cause us to have long-lived asset, including finite-lived intangible assets, impairment losses in 2016 or later within our well site services business segment. At December 31, 2015, long-lived assets and finite-lived intangibles assets totaled approximately $328 million and $96 million in our completion services and drilling services businesses, respectively.

We evaluate each reporting unit at least annually or on an interim basis, if an indicator of impairment was determined to occur, as defined in current accounting standards regarding goodwill to assess goodwill for potential impairment. Our reporting units include completion services, drilling services and offshore products. There is no remaining goodwill in our drilling services reporting unit subsequent to the full impairment of goodwill for that reporting unit as of December 31, 2008. 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 2015, we performed the two-step impairment test given stock market value declines in the energy sector and 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. 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 2015, the IFV of our offshore products and completion services reporting units each exceeded their carrying values by 79% and 68%, respectively. Subsequent to December 31, 2015 and continuing through the date of this filing, crude oil prices have continued to decline and our market capitalization was $1.29 billion at February 18, 2016 as compared to the carrying value of our equity of December 31, 2015 of $1.26 billion. A continuation of the current industry downturn during 2016 will likely 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.

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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 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.

Allowance for Doubtful Accounts

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, 2015 and 2014, allowance for bad debts totaled $6.9 million and $7.1 million, or 2.0% and 1.4% of gross accounts receivable, respectively. Historically, the Company’s charge-offs and provisions for the allowance for doubtful accounts have been immaterial to the Company’s consolidated financial statements.

Inventory Reserves

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, 2015 and 2014, inventory reserves totaled $12.9 million and $9.9 million, or 5.7% and 4.1% of gross inventory, respectively.

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Estimation of Useful Lives

The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. 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.

Stock-Based Compensation

Since the adoption of the accounting standards regarding share-based payments, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An estimate of the fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black-Scholes-Merton “closed form” model to value stock options awarded under the Plan. Utilizing the Black-Scholes-Merton model requires us to estimate the length of time options will remain outstanding, a risk-free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.

Income Taxes

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.

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

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

Recent Accounting Pronouncements

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

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In November 2015, the FASB issued guidance on the balance sheet classification of deferred taxes which requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this new guidance. For public business entities, the guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. Due to its simplification of the accounting for and presentation of deferred income taxes, we have elected to early adopt this guidance prospectively in the fourth quarter of 2015 and, as a result, have presented all deferred tax assets and liabilities as noncurrent on our consolidated balance sheet as of December 31, 2015, but have not adjusted our December 31, 2014 consolidated balance sheet as a result of this adoption.

In September 2015, the FASB issued guidance on measurement-period adjustments for business combinations which require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period with a corresponding adjustment to goodwill in the reporting period in which the adjustment amounts are determined, as opposed to revising prior periods presented in financial statements as previously required. Thus, an acquirer shall record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This guidance requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. For public business entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. This guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this guidance with earlier application permitted for financial statements that have not been issued. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

In July 2015, the FASB issued guidance on the measurement of inventory which simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under this guidance, in scope inventory should be measured at the lower of cost and net realizable value. This guidance is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We are evaluating the impact of this guidance on our consolidated financial statements and our timing for adoption but do not expect that the adoption of this guidance will have a material effect on our consolidated financial statements.

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. In August 2015, the FASB issued additional guidance on this topic which adds comments from the Commission addressing the guidance issued in April 2015 and debt issuance costs related to line-of-credit arrangements. The Commission commented it would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for debt issuance costs are not affected by this guidance. For public business entities, this guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

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 in exchange for those goods or services. The guidance provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include capitalization of certain contract costs, consideration of time value of money in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. The guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. In August 2015, the FASB issued guidance deferring the effective date by one year to December 15, 2017 for fiscal years, and interim periods within those years, beginning after that date and permitted early adoption of the standard, but not before the original effective date of December 15, 2016. The guidance permits the use of either a retrospective or cumulative effect transition method. We have not yet selected a transition method and continue to evaluate the impact of the amended guidance on our consolidated financial position, results of operations and related disclosures.

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ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

Market risk refers to the potential 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, 2015, we had floating-rate obligations totaling $122.9 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, 2015 levels, our consolidated interest expense would increase by a total of approximately $1.2 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 2015, our reported foreign exchange gains were $3.7 million and are included in “Other operating expense” in the Consolidated Statements of Income. 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, 2015 and 2014, we had outstanding foreign currency forward purchase contracts with notional amounts of $5.4 million related to expected cash flows denominated in Euros. As a result of these contracts, we recorded other comprehensive income of $0.3 million for the year ended December 31, 2015 and a $0.4 million foreign exchange loss related to amounts reclassified from accumulated other comprehensive loss into an expense on the income statement for the year ended December 31, 2015.

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, increased from $22.1 million at December 31, 2014 to $50.7 million at December 31, 2015, primarily as a result of foreign currency exchange rate differences in the current year of $27.8 million. This other comprehensive loss is primarily related to fluctuations in the foreign currency exchange rates compared to the U.S. dollar which are used to remeasure the foreign operations of our reportable segments (primarily in the United Kingdom, Brazil, and Canada) and certain foreign currency denominated intercompany borrowings. The average exchange rates of the British pound, Brazilian real, and Canadian dollar compared to the U.S. dollar weakened by 5%, 31%, and 16%, respectively, in 2015 compared to 2014.

Item 8. Financial Statements and Supplementary Data

Our Consolidated Financial Statements and supplementary data of the Company begin on page 64 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.

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

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

Item 9A. Controls and Procedures

(i) Evaluation of Disclosure Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2015 at the reasonable assurance level.

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

(ii) Internal Control over Financial Reporting

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

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with 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, 2015 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, 2015, the Company's internal control over financial reporting is effective based on those criteria.

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

The attestation report of Ernst & Young LLP, the Company's independent registered public accounting firm, on the Company's internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 66 and is incorporated herein by reference.

(c) Changes in internal control over financial reporting.

During the Company's fourth fiscal quarter ended December 31, 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2015 that was not reported on a Form 8-K during such time.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

(1)

Information concerning directors, including the Company's audit committee financial expert, appears in the Company's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, under "Election of Directors." This portion of the Definitive Proxy Statement is incorporated herein by reference.

(2)

Information with respect to executive officers appears in the Company's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, under "Executive Officers of the Registrant." This portion of the Definitive Proxy Statement is incorporated herein by reference.

(3)

Information concerning Section 16(a) beneficial ownership reporting compliance appears in the Company's Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders, under "Section 16(a) Beneficial Ownership Reporting Compliance." This portion of the Definitive Proxy Statement is incorporated herein by reference.

Item 11. Executive Compensation

The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2016 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 2016 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 2016 Annual Meeting of Stockholders.

Item 14. Principal Accounting Fees and Services

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 2016 Annual Meeting of Stockholders under the heading "Fees Paid to Ernst & Young LLP" and is incorporated herein by reference.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

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

(1) Financial Statements: Reference is made to the index set forth on page 64 of this Annual Report on Form 10-K.

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

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

(b)

Index of Exhibits

Exhibit No.		Description

2.1	—	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)).

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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 February 19, 2013 (incorporated by reference to Exhibit 10.1 to the Company’s' Quarterly Report on Form 10-Q, as filed with the Commission on July 31, 2013 (File No. 001-16337)).

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 (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).

10.5**	—	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**	—	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)).

10.9**	—	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)).

10.10**	—	Form of Employee Non Qualified Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

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10.11**	—	Form of Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).

10.12**	—	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)).

10.13**	—	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)).

10.14**	—	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)).

10.15**	—	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)).

10.16**	—	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)).

10.17**	—	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)).

10.18**	—	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)).

10.19**	—	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)).

10.20**	—	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)).

10.21	—	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)).

10.22	—	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)).

10.23	—	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)).

10.24	—	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)).

10.25**	—	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)).

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21.1*	—	List of subsidiaries of the Company.

23.1*	—	Consent of Independent Registered Public Accounting Firm.

24.1*	—	Powers of Attorney for Directors.

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

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

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

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

101.INS*	—	XBRL Instance Document

101.SCH*	—	XBRL Taxonomy Extension Schema Document

101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

---------

* Filed herewith

** Management contracts or compensatory plans or arrangements

*** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 19, 2016.

	OIL STATES INTERNATIONAL, INC.


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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 19, 2016.

	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	Senior Vice President, Chief Financial Officer and Treasurer
	Lloyd A. Hajdik	(Principal Financial Officer)

	/s/ SARAH A.MUNSON	Vice President, Controller and Chief Accounting Officer
	Sarah A. Munson	(Principal Accounting Officer)

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

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

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

	/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


*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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

INDEX TO

CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements	65
Report of Independent Registered Public Accounting Firm on the Company's Internal Control Over Financial Reporting	66
Consolidated Statements of Income	67
Consolidated Statements of Comprehensive Income	68
Consolidated Balance Sheets	69
Consolidated Statements of Stockholders' Equity	70
Consolidated Statements of Cash Flows	71
Notes to Consolidated Financial Statements	72 – 93

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2015. 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, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, 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 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2015, 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, 2015, 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, 2015 and 2014, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015 and our report dated February 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2016

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2015			2014			2013
Revenues:
Product	$	561,018		$	765,339		$	714,787
Service and other		538,959			1,054,270			914,347
		1,099,977			1,819,609			1,629,134

Costs and expenses:
Product costs		395,137			546,639			536,660
Service and other costs		390,561			659,245			576,508
Selling, general and administrative expenses		132,664			169,432			150,967
Depreciation and amortization expense		131,257			124,776			109,231
Other operating (income) expense, net		(4,648	)		9,262			8,491
		1,044,971			1,509,354			1,381,857
Operating income		55,006			310,255			247,277

Interest expense		(6,427	)		(17,173	)		(38,830	)
Interest income		543			560			628
Loss on extinguishment of debt		--			(100,380	)		(6,168	)
Other income		1,446			3,082			1,220
Income from continuing operations before income taxes		50,568			196,344			204,127
Income tax provision		(22,197	)		(69,117	)		(75,068	)
Net income from continuing operations		28,371			127,227			129,059
Net income from discontinued operations, net of tax (including a net gain on disposal of $84,043 in 2013)		226			51,776			292,217
Net income		28,597			179,003			421,276
Less: Net income attributable to noncontrolling interest		--			--			18
Net income attributable to Oil States International, Inc.	$	28,597		$	179,003		$	421,258


Net income attributable to Oil States International, Inc.:
Continuing operations	$	28,371		$	127,227		$	129,041
Discontinued operations		226			51,776			292,217
Net income attributable to Oil States International, Inc.	$	28,597		$	179,003		$	421,258

Basic net income per share attributable to Oil States International, Inc. common stockholders from:
Continuing operations	$	0.55		$	2.37		$	2.32
Discontinued operations		0.01			0.96			5.26
Net income	$	0.56		$	3.33		$	7.58

Diluted net income per share attributable to Oil States International, Inc. common stockholders from:
Continuing operations	$	0.55		$	2.35		$	2.31
Discontinued operations		0.01			0.96			5.22
Net income	$	0.56		$	3.31		$	7.53

Weighted average number of common shares outstanding:
Basic		50,269			52,862			54,969
Diluted		50,335			53,151			55,327

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

	Year Ended December 31,
	2015			2014			2013

Net income	$	28,597		$	179,003		$	421,276

Other comprehensive (loss) income:
Foreign currency translation adjustment		(27,957	)		235			(193,191	)
Unrealized gain on forward contracts, net of tax		307			6			402
Other		(948	)		(185	)		17
Total other comprehensive (loss) income		(28,598	)		56			(192,772	)

Comprehensive (loss) income		(1	)		179,059			228,504
Less: Comprehensive loss attributable to noncontrolling interest		--			(24	)		(73	)
Comprehensive (loss) income attributable to Oil States International, Inc.	$	(1	)	$	179,083		$	228,577

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

-68-

OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	35,973		$	53,263
Accounts receivable, net		333,494			497,124
Inventories, net		212,882			232,490
Prepaid expenses and other current assets		29,124			43,789
Total current assets		611,473			826,666

Property, plant and equipment, net		638,725			649,846
Goodwill, net		263,787			252,201
Other intangible assets, net		59,385			53,884
Other noncurrent assets		25,768			27,015
Total assets	$	1,599,138		$	1,809,612

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	59,116		$	108,949
Accrued liabilities		49,300			96,130
Income taxes		8,303			9,195
Current portion of long-term debt and capitalized leases		533			530
Deferred revenue		36,655			48,948
Deferred tax liabilities		--			7,431
Other current liabilities		293			229
Total current liabilities		154,200			271,412

Long-term debt and capitalized leases		128,554			146,835
Deferred income taxes		40,497			33,913
Other noncurrent liabilities		20,215			16,795
Total liabilities		343,466			468,955

Stockholders' equity:
Oil States International, Inc. stockholders' equity:
Common stock, $.01 par value, 200,000,000 shares authorized, 61,712,805 shares and 60,940,734 shares issued, respectively, and 50,953,149 shares and 53,017,359 shares outstanding, respectively		617			610
Additional paid-in capital		712,980			685,232
Retained earnings		1,179,863			1,151,266
Accumulated other comprehensive loss		(50,698	)		(22,100	)
Common stock held in treasury at cost, 10,759,656 and 7,923,375 shares, respectively		(587,090	)		(474,351	)
Total Oil States International, Inc. stockholders' equity		1,255,672			1,340,657
Noncontrolling interest		--			--
Total stockholders' equity		1,255,672			1,340,657
Total liabilities and stockholders' equity	$	1,599,138		$	1,809,612

The accompanying notes are an integral part of these financial statements

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In Thousands)

	Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Noncontrolling Interest			Total Stockholders' Equity
Balance, December 31, 2012	$	585	$	586,070		$	1,899,195		$	107,097		$	(128,542	)	$	1,395		$	2,465,800
Net income							421,258									18			421,276
Currency translation adjustment										(193,191	)					(91	)		(193,282	)
Other comprehensive income										17									17
Unrealized gain on forward contracts, net of tax										402									402
Dividends paid																(882	)		(882	)
Exercise of stock options, including tax impact		5		23,786															23,791
Amortization of restricted stock compensation				21,121															21,121
Stock option expense				5,153															5,153
Surrender of stock to pay taxes on restricted stock awards		2		(2	)								(4,919	)					(4,919	)
Stock repurchases													(115,932	)					(115,932	)
Exercise of stock options/stock awards released – discontinued operations				1,292															1,292
Net income from noncontrolling interest – discontinued operations																1,437			1,437
Other				18									2						20
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
Currency translation adjustment										235						(24	)		211
Other comprehensive income										(185	)								(185	)
Unrealized gain on forward contracts, net of tax										6									6
Dividends paid																(489	)		(489	)
Exercise of stock options, including tax impact		4		17,124															17,128
Amortization of restricted stock compensation				23,513															23,513
Stock option expense				3,636															3,636
Surrender of stock to pay taxes on restricted stock awards													(6,136	)					(6,136	)
Stock repurchases													(218,906	)					(218,906	)
Exercise of stock options/stock awards released – discontinued operations				2,727															2,727
Net income from noncontrolling interest – discontinued operations																566			566
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	)
Acquisition of non-controlling interest				(184	)											(166	)		(350	)
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 notes)										(24,191	)								(24,191	)
Currency translation adjustment on intercompany notes										(3,766	)								(3,766	)
Other comprehensive income										(948	)								(948	)
Unrealized gain on forward contracts, net of tax										307									307
Exercise of stock options, including tax impact		3		5,977															5,980
Amortization of restricted stock compensation				18,836															18,836
Stock option expense				2,942															2,942
Restricted stock awards granted		4		(4	)														--
Surrender of stock to pay taxes on restricted 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

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income	$	28,597		$	179,003		$	421,276
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(226	)		(51,776	)		(292,217	)
Depreciation and amortization		131,257			124,776			109,231
Deferred income tax benefit		(3,173	)		(11,970	)		(9,759	)
Tax impact of share-based payment arrangements		(469	)		(6,904	)		(7,407	)
Gains on disposals of assets		(1,274	)		(2,043	)		(1,090	)
Non-cash compensation charge		21,778			25,581			24,097
Amortization of deferred financing costs		780			1,819			4,146
Loss on extinguishment of debt		--			100,380			6,168
Other, net		283			3,127			4,459
Changes in operating assets and liabilities, net of effect from acquired businesses:
Accounts receivable		156,945			(65,787	)		801
Inventories		17,777			1,430			(691	)
Accounts payable and accrued liabilities		(98,354	)		5,741			3,163
Taxes payable		4,897			(15,130	)		(3,442	)
Other operating assets and liabilities, net		(3,050	)		14,397			(23,649	)
Net cash flows provided by continuing operating activities		255,768			302,644			235,086
Net cash flows provided by discontinued operating activities		353			135,392			452,177
Net cash flows provided by operating activities		256,121			438,036			687,263

Cash flows from investing activities:
Capital expenditures		(114,738	)		(199,256	)		(164,895	)
Acquisitions of businesses, net of cash acquired		(33,427	)		(157	)		(44,260	)
Proceeds from sale of business		--			--			600,000
Proceeds from disposition of property, plant and equipment		2,655			3,535			2,449
Other, net		(1,686	)		(2,626	)		215
Net cash flows (used in) provided by continuing investing activities		(147,196	)		(198,504	)		393,509
Net cash flows used in discontinued investing activities		--			(119,199	)		(285,132	)
Net cash flows (used in) provided by investing activities		(147,196	)		(317,703	)		108,377

Cash flows from financing activities:
Revolving credit (repayments) borrowings, net		(17,825	)		140,684			--
Repayment of 6 1/2% Senior Notes		--			(630,307	)		--
Repayment of 5 1/8% Senior Notes		--			(419,794	)		(37,750	)
Distribution received from Spin-Off of Civeo		--			750,000			--
Term loan repayments		--			--			(170,000	)
Debt and capital lease repayments		(541	)		(538	)		(2,303	)
Issuance of common stock from share based payment arrangements		5,920			10,475			16,384
Purchase of treasury stock		(105,916	)		(226,303	)		(108,535	)
Tax impact of share based payment arrangements		469			6,904			7,407
Payment of financing costs		(2	)		(3,897	)		(212	)
Shares added to treasury stock as a result of net share settlements due to vesting of restricted stock		(6,827	)		(6,136	)		(4,919	)
Net cash flows used in continuing financing activities		(124,722	)		(378,912	)		(299,928	)
Net cash flows used in discontinued financing activities		--			(282,204	)		(130,668	)
Net cash flows used in financing activities		(124,722	)		(661,116	)		(430,596	)

Effect of exchange rate changes on cash		(1,493	)		(5,260	)		(18,910	)
Net change in cash and cash equivalents		(17,290	)		(546,043	)		346,134
Cash and cash equivalents, beginning of year		53,263			599,306			253,172

Cash and cash equivalents, end of year	$	35,973		$	53,263		$	599,306

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

The Consolidated Financial Statements include the accounts of Oil States International, Inc. (Oil States or the Company) and its consolidated subsidiaries. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying Consolidated Financial Statements. Certain prior year amounts in the Company’s Consolidated Financial Statements have been reclassified to conform to the current year presentation.

On May 30, 2014, we completed the spin-off of our accommodations business into a stand-alone, publicly traded corporation (Civeo Corporation, or Civeo) (the Spin-Off). The results of operations for our accommodations business have been classified as discontinued operations for all periods presented. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

The Company, through its subsidiaries, is a leading provider of specialty products and services to oil and gas companies throughout the world. We operate in a substantial number of the world's active oil and natural gas producing regions, onshore and offshore U.S., Canada, West Africa, the North Sea, South America and Southeast and Central Asia. The Company operates in two principal reportable business segments – offshore products and well site services.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

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

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, 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 income.

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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 at December 31, 2015 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 2015, we performed the two-step impairment test given stock value declines in the energy sector and 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. We conduct our annual impairment test as of December of each year. In 2013, 2014 and 2015, 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 Income

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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Foreign Currency Exchange Rate Risk

A portion of revenues, earnings and net investments in foreign affiliates are exposed to changes in foreign currency exchange rates. We seek to manage our foreign exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. 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, 2015 and 2014, we had outstanding foreign currency forward purchase contracts with notional amounts of $5.4 million related to expected cash flows denominated in Euros. As a result of these contracts, we recorded other comprehensive income of $0.3 million and $0.4 million, respectively, for the years ended December 31, 2015 and December 31, 2013. In addition, we recorded $0.4 million and $0.9 million, respectively, in foreign exchange losses related to amounts reclassified from accumulated other comprehensive loss into an expense on the income statement for the years ended December 31, 2015 and December 31, 2013. Foreign exchange gains and losses have totaled gains of $3.7 million in 2015 and losses of $0.4 million and $1.6 million in 2014 and 2013, respectively, 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)

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. Management will continue to evaluate the appropriateness of the valuation allowance in the future based upon the operating results of the Company.

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 rest of our business.

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 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, some of 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 shareholders 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 (EPS) 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 applicable to the Company’s common shareholders 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 option-pricing models based on the grant-date fair value of the award. 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 2015, 2014 and 2013, 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. The performance-based awards issued in 2014 and 2015 have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital. During the years ended December 31, 2015, 2014 and 2013, the Company recognized non-cash general and administrative expenses for stock options and restricted stock awards totaling $21.8 million, $25.6 million and $22.5 million, respectively.

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 $2.6 million and $2.8 million at December 31, 2015 and 2014, 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, 2015, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements (letters of credit) was $46.6 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 potential future adjustments as a result of contingent consideration arrangements pursuant to business combinations and other contractual agreements, 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. 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

Subsequent Events

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

3. Details of Selected Balance Sheet Accounts

Additional information regarding selected balance sheet accounts at December 31, 2015 and 2014 is presented below (in thousands):

	2015			2014
Accounts receivable, net:
Trade	$	210,313		$	348,115
Unbilled revenue		124,331			148,371
Other		5,738			7,763
Total accounts receivable		340,382			504,249
Allowance for doubtful accounts		(6,888	)		(7,125	)
	$	333,494		$	497,124

	2015			2014
Inventories, net:
Finished goods and purchased products	$	97,362		$	94,955
Work in process		42,182			49,631
Raw materials		86,236			97,780
Total inventories		225,780			242,366
Allowance for excess, damaged, or obsolete inventory		(12,898	)		(9,876	)
	$	212,882		$	232,490

	Estimated Useful Life (years)			2015			2014
Property, plant and equipment, net:
Land				$	26,334		$	29,850
Buildings and leasehold improvements	3	-	40		185,274			175,421
Machinery and equipment	2	-	28		462,054			438,980
Completion services equipment	2	-	10		421,386			387,165
Office furniture and equipment	3	-	10		32,200			30,647
Vehicles	2	-	10		125,211			129,922
Construction in progress					92,800			74,088
Total property, plant and equipment					1,345,259			1,266,073
Accumulated depreciation					(706,534	)		(616,227	)
				$	638,725		$	649,846

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	2015		2014
Accrued liabilities:
Accrued compensation	$	19,402	$	58,979
Insurance liabilities		9,855		11,300
Accrued taxes, other than income taxes		3,619		4,851
Accrued leasehold restoration liability		3,389		--
Accrued commissions		2,033		3,621
Accrued product warranty reserves		2,638		2,809
Accrued claims		896		8,000
Other		7,468		6,570
	$	49,300	$	96,130

Depreciation expense was $123.5 million, $117.7 million and $104.2 million for the years ended December 31, 2015, 2014 and 2013, respectively.

4. Recent Accounting Pronouncements

In September 2015, the FASB issued guidance on measurement-period adjustments for business combinations which require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period with a corresponding adjustment to goodwill in the reporting period in which the adjustment amounts are determined, as opposed to revising prior periods presented in financial statements as previously required. Thus, an acquirer shall record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. This guidance requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. For public business entities, the guidance is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. This guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date of this guidance with earlier application permitted for financial statements that have not been issued. We do not expect that the adoption of this standard will have a material effect on our consolidated financial statements.

In July 2015, the FASB issued guidance on the measurement of inventory which simplifies the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under this guidance, inventory should be measured at the lower of cost and net realizable value. This guidance is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We are evaluating the impact of this guidance on our consolidated financial statements and our timing for adoption but do not expect that the adoption of this guidance will have a material effect on our consolidated financial statements.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

5. Accumulated Other Comprehensive Loss

Our accumulated other comprehensive loss, reported as a component of stockholders’ equity, increased from $22.1 million at December 31, 2014 to $50.7 million at December 31, 2015, primarily as a result of foreign currency exchange rate differences. Our accumulated other comprehensive loss is primarily related to fluctuations in the foreign currency exchange rates compared to the U.S. dollar which are used to remeasure the foreign operations of our reportable segments (primarily in the United Kingdom, Brazil, and Canada). The average exchange rates of the British pound, Brazilian real, and Canadian dollar compared to the U.S. dollar weakened by 5%, 31%, and 16%, respectively, in 2015 compared to 2014.

6. Acquisitions and Supplemental Cash Flow Information

Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2015 and 2013 are summarized as follows (in thousands):

	2015			2013
Fair value of assets acquired including intangibles and goodwill	$	39,505		$	66,825
Liabilities/equity assumed		(6,026	)		(19,986	)
Noncash consideration		--			(2,568	)
Cash acquired		(52	)		(11	)
Cash used in acquisitions of businesses	$	33,427		$	44,260

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

2015

On January 2, 2015, we acquired all of the equity of Montgomery Machine Company, Inc. (MMC). Headquartered in Houston, Texas, MMC combines machining and proprietary cladding technology and services to manufacture high-specification components for the offshore capital equipment industry. We believe that the acquisition of MMC will strengthen our position in our offshore products segment 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. The operations of MMC have been included in our offshore products segment since the acquisition date.

2013

The Company funded all of its acquisitions with cash on hand and/or amounts available under our credit facilities. See Note 10 – Long-term Debt for additional information on our senior secured credit facilities.

Supplemental Cash Flow Information

Cash paid during the years ended December 31, 2015, 2014 and 2013 for interest and income taxes was as follows (in thousands):

	2015		2014		2013
Interest (net of amounts capitalized)	$	5,629	$	40,375	$	56,663
Income taxes, net of refunds	$	18,780	$	102,160	$	90,927

Non-cash financing activities:
Borrowings and contingent consideration for business and asset acquisition and related intangibles	$	--	$	--	$	1,175

7. Discontinued Operations

On May 30, 2014, we completed the Spin-Off of our accommodations business, Civeo Corporation, to the Company’s stockholders. On May 30, 2014, the stockholders of record of Oil States common stock as of the close of business on May 21, 2014 (the Record Date) received two shares of Civeo common stock for each share of Oil States common stock held as of the Record Date. Following the Spin-Off, Oil States ceased to own any shares of Civeo common stock.

The following table provides the components of net income from discontinued operations, net of tax for each operating segment (in thousands). The $128.4 million ($84.0 million after-tax) net gain related to the disposal of Sooner in 2013 was excluded.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	2015			2014			2013
Revenues
Accommodations	$	--		$	404,207		$	1,041,104
Tubular services	$	--		$	--		$	1,073,096

Income from Accommodations discontinued operations:
Income from discontinued operations before income taxes	$	327		$	62,504		$	230,778
Income tax expense		(118	)		(11,004	)		(44,925	)
Net income from discontinued operations, net of tax	$	209		$	51,500		$	185,853

Income from Tubular services discontinued operations:
Income from discontinued operations before income taxes	$	27		$	321		$	40,964
Income tax expense		(10	)		(45	)		(18,643	)
Net income from discontinued operations, net of tax	$	17		$	276		$	22,321

8. Earnings Per Share (EPS)

The numerator (income) and denominator (shares) used for the computation of basic and diluted earnings per share from continuing operations were as follows (in thousands):

	2015					2014					2013
	Income			Shares		Income			Shares		Income			Shares
Basic:
Net income attributable to Oil States International, Inc.	$	28,597				$	179,003				$	421,258
Less: Undistributed net income allocable to participating securities		(597	)				(2,948	)				(4,573	)
Undistributed net income applicable to common stockholders		28,000					176,055					416,685
Less: Income from discontinued operations, net of tax		(226	)				(51,776	)				(292,217	)
Add: Undistributed net income from discontinued operations allocable to participating securities		5					853					3,172
Income from continuing operations applicable to Oil States International, Inc. common stockholders – Basic	$	27,779			50,269	$	125,132			52,862	$	127,640			54,969
Diluted:
Income from continuing operations applicable to Oil States International, Inc. common stockholders - Basic	$	27,779			50,269	$	125,132			52,862	$	127,640			54,969
Effect of dilutive securities:
Undistributed net income reallocated to participating securities		1			--		11			--		9			--
Options on common stock		--			57		--			274		--			341
Restricted stock awards and other		--			9		--			15		--			17
Income from continuing operations applicable to Oil States International, Inc. common stockholders - Diluted		27,780			50,335		125,143			53,151		127,649			55,327
Income from discontinued operations, net of tax, applicable to Oil States International, Inc. common stockholders		221					50,923					289,045
Undistributed net income reallocated to participating securities		--					5					20
Net income attributable to Oil States International, Inc. common stockholders - Diluted	$	28,001			50,335	$	176,071			53,151	$	416,714			55,327

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Our calculation of diluted earnings per share for the years ended December 31, 2015, 2014 and 2013 excluded 747,839 shares, 224,739 shares and 263,838 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.

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 with goodwill as of December 31, 2015. 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, 2015, no provision for impairment of other intangible assets was required.

Changes in the carrying amount of goodwill for the years ended December 31, 2015 and 2014 are as follows (in thousands):

		Well Site Services
		Completion Services			Drilling Services			Subtotal			Accommodations			Offshore Products			Total
Balance as of December 31, 2013
Goodwill	$	201,911		$	22,767		$	224,678		$	261,056		$	145,211		$	630,945
Accumulated Impairment Losses		(94,528	)		(22,767	)		(117,295	)		--			--			(117,295	)
		107,383			--			107,383			261,056			145,211			513,650
Spin-Off of Civeo		--			--			--			(268,463	)		--			(268,463	)
Goodwill acquired and purchase price adjustments		193			--			193			--			882			1,075
Foreign currency translation and other changes		(1,137	)		--			(1,137	)		7,407			(331	)		5,939
		106,439			--			106,439			--			145,762			252,201

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	)
		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

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table presents the total amount of intangibles assigned and the total accumulated amortization for major intangible asset classes as of December 31, 2015 and 2014 (in thousands):

	As of December 31,
	2015				2014
Other Intangible Assets	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationships	$	44,557	$	15,790	$	37,803	$	12,399
Contracts/Agreements/Backlog		1,064		355		--		--
Patents		20,024		6,521		18,731		5,250
Technology		10,111		3,052		10,110		2,041
Noncompete agreements		4,358		1,565		3,968		915
Trademarks and other		8,237		1,683		5,914		2,037
Total other intangible assets	$	88,351	$	28,966	$	76,526	$	22,642

The weighted average remaining amortization period for all intangible assets, other than goodwill, was 8.7 years as of December 31, 2015 and 9.3 years as of December 31, 2014. Total amortization expense is expected to be $7.9 million in 2016, $7.8 million in 2017, $7.1 million in 2018, $6.9 million in 2019 and $6.6 million in 2020. Amortization expense was $7.8 million, $7.0 million and $5.1 million in the years ended December 31, 2015, 2014 and 2013, respectively.

10. Long-term Debt

As of December 31, 2015 and 2014, long-term debt consisted of the following (in thousands):

	2015		2014
Revolving credit facility, which matures May 28, 2019, with available commitments up to $600 million; secured by substantially all of our U.S. assets; commitment fee on unused portion of 0.375 % per annum in 2015 and 2014; variable interest rate payable monthly based on LIBOR plus applicable percentage; weighted average interest rate was 1.9% for 2015 and 1.8% for 2014	$	122,858	$	140,684

Capital lease obligations and other debt		6,229		6,681
Total debt		129,087		147,365
Less: Current portion		533		530
Total long-term debt and capitalized leases	$	128,554	$	146,835

Scheduled maturities of combined long-term debt as of December 31, 2015, are as follows (in thousands):

2016	$	533
2017		538
2018		449
2019		123,201
2020		359
Thereafter		4,007
	$	129,087

The Company's capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $1.5 million and $0.9 million, respectively, at December 31, 2015. The value of capitalized leases and the related accumulated depreciation totaled $1.5 million and $0.7 million, respectively, at December 31, 2014.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Credit Facility

In connection with the Spin-Off, the Company terminated its then existing bank credit facility on May 28, 2014 and entered into a new $600 million senior secured revolving credit facility. The Company has 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. The credit facility is governed by a Credit Agreement dated as of May 28, 2014 (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. 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 (as defined in the Credit Agreement). From May 28, 2014 through December 31, 2014, 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 period May 28, 2014 through December 31, 2014. 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, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2015, we were in compliance with our debt covenants.

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 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.

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

As of December 31, 2015, we had $122.9 million outstanding under the Credit Agreement and an additional $37.7 million of outstanding letters of credit, leaving $439.4 million available to be drawn under the credit facility. However, the total amount available to be drawn under our revolving credit facility is expected to be significantly reduced as our trailing twelve months EBITDA moves lower into 2016 given that, in accordance with the Credit Agreement, total debt cannot exceed 3.25 times our trailing twelve months EBITDA. As of December 31, 2015, the Company had $36.0 million of cash and cash equivalents.

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 the second quarter 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. During 2013, we recognized a loss on the extinguishment of debt totaling $6.2 million from the repurchase of a portion of our 5 1/8% Notes in the fourth quarter of 2013, resulting in a loss of $4.1 million, including the write-off of $0.4 million of unamortized deferred financing costs. Additionally, we wrote off $2.1 million of unamortized deferred financing costs associated with the full repayment of our U.S. term loan.

11. Stock Repurchase Program

On September 6, 2013, the Company announced an increase in its Board-authorized Company stock repurchase program from $200 million to $500 million providing for the repurchase of the Company’s common stock, par value $.01 per share. On July 29, 2015, the Company’s Board of Directors approved the termination of our existing share repurchase program and authorized a new program providing for the repurchase of up to $150 million of the Company’s common stock, par value $.01 per share. The new program is set to expire on July 29, 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. As of December 31, 2015, a total of $456.0 million of our stock (6,902,748 shares, or approximately 13% of the outstanding shares of our common stock at the initiation of our initial share repurchase authorization in August 2012) had been repurchased under these programs. The amount remaining under our current share repurchase authorization as of December 31, 2015 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.

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

12. Retirement Plans

The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $8.0 million, $13.0 million and $9.7 million, respectively, related to matching contributions under its various defined contribution plans during the years ended December 31, 2015, 2014 and 2013, respectively.

13. Income Taxes

Consolidated income (loss) from continuing operations before income taxes for the years ended December 31, 2015, 2014 and 2013 consisted of the following (in thousands):

	2015			2014		2013
US operations	$	(21,598	)	$	128,639	$	143,913
Foreign operations		72,166			67,705		60,214
Total	$	50,568		$	196,344	$	204,127

The components of the income tax provision (benefit) for the years ended December 31, 2015, 2014 and 2013 consisted of the following (in thousands):

	2015			2014			2013
Current:
Federal	$	7,221		$	56,317		$	65,249
State		1,868			5,426			2,881
Foreign		16,281			19,344			16,697
		25,370			81,087			84,827
Deferred:
Federal		(5,656	)		(8,620	)		(11,468	)
State		(496	)		26			263
Foreign		2,979			(3,376	)		1,446
		(3,173	)		(11,970	)		(9,759	)
Total Provision	$	22,197		$	69,117		$	75,068

A reconciliation of the federal statutory tax rate to the effective tax rate for the years ended December 31, 2015, 2014 and 2013 is as follows:

	2015			2014			2013
Federal statutory tax rate		35.0	%		35.0	%		35.0	%
Effect of foreign income tax, net		(11.1	)		(2.8	)		(0.4	)
Valuation allowance		8.1			--			--
Nondeductible compensation		7.6			0.3			0.2
Other nondeductible expenses		4.5			1.4			2.2
Domestic manufacturing deduction		(2.6	)		(1.9	)		(2.1	)
State tax expense, net of federal benefits		1.3			2.8			1.5
Other, net		1.1			0.4			0.4
Effective tax rate		43.9	%		35.2	%		36.8	%

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OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2015 and 2014 are as follows (in thousands):

	2015			2014
Deferred tax assets:
Foreign tax credit carryover	$	24,852		$	27,771
Employee benefits		18,252			22,036
Allowance for inventory reserves		7,394			7,102
Net operating loss carryforward		4,580			2,700
Other reserves		3,580			5,659
Allowance for doubtful accounts		1,657			1,526
Other		635			1,365
Gross deferred tax asset		60,950			68,159
Valuation allowance		(3,970	)		--
Deferred tax asset		56,980			68,159
Deferred tax liabilities:
Tax over book depreciation		(77,632	)		(93,010	)
Intangible assets		(17,804	)		(9,700	)
Accrued liabilities		(1,513	)		(2,298	)
Deferred revenue		(113	)		(1,171	)
Other		(377	)		(458	)
Deferred tax liability		(97,439	)		(106,637	)
Net deferred tax liability		(40,459	)	$	(38,478	)

Our primary deferred tax assets at December 31, 2015, were related to foreign tax credit carryforwards, employee benefit costs for our Equity Participation Plan and allowance for inventory obsolescence. The foreign tax credits will expire in varying amounts from 2021 to 2024.

At December 31, 2015 the Company had state net operating loss (NOL) carryforwards of $15.8 million and foreign NOL carryforwards of $0.7 million, $2.6 million and $7.3 million for India, Thailand, and Brazil, respectively. The NOL carryforwards for states will expire between 2021and 2035. 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 $248.7 million at December 31, 2015, the majority of which has been generated in the U.K. (before the Company’s representation to permanently reinvest earnings in the U.K. 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 2015, we repatriated $35.2 million from our foreign subsidiaries which was used to reduce outstanding borrowings under our 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 50 percent likely of being realized upon ultimate settlement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The total amount of unrecognized tax benefits as of December 31, 2015 and December 31, 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, 2015 and 2014, the Company had no accrued interest expense or penalties.

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

		2015		2014			2013
Balance as of January 1^st	$	--	$	836		$	728
Additions for tax positions of prior years		--		--			108
Distribution to Civeo		--		(836	)		--
Balance as of December 31^st	$	--	$	--		$	836

14. Commitments and Contingencies

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

Minimum future operating lease obligations in effect at December 31, 2015, were as follows (in thousands):

	Operating Leases
2016	$	8,271
2017		4,784
2018		3,422
2019		2,654
2020		1,298
Thereafter		5,738
Total	$	26,167

Rental expense under operating leases was $11.3 million, $11.5 million and $12.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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 is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period.

Stock-based compensation pre-tax expense from continuing operations recognized in the years ended December 31, 2015, 2014 and 2013 totaled $21.8 million, $25.6 million and $22.5 million, respectively.

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, 2014 and 2013 was based on a formula considering the vesting period, term of the options awarded and past experience.

	2015			2014			2013

Risk-free weighted interest rate		1.2	%		1.3	%		0.6	%

Expected life (in years)		4.3			4.1			4.1

Expected volatility		37	%		38	%		44	%

The following table presents the changes in stock options outstanding and related information for the year ended December 31, 2015:

	Options			Weighted Average Exercise Price Per Share	Weighted Average Contractual Life (Years)		Aggregate Intrinsic Value (thousands)
Outstanding Options at December 31, 2014	1,007,686		$	38.97	5.4	$	11,877
Granted	119,370			42.29
Exercised	(336,251	)		37.01
Forfeited/Expired	(20,624	)		50.96
Outstanding Options at December 31, 2015	770,181			48.49	7.0	$	88


Exercisable Options at December 31, 2015	370,268		$	47.18	5.9	$	88

The weighted average fair values of options granted during 2015, 2014 and 2013 were $13.32, $32.03, and $28.31 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 2015, 2014 and 2013 were $12.4 million, $28.1 million and $43.6 million, respectively. Cash received by the Company from option exercises during 2015, 2014 and 2013 totaled $5.9 million, $10.5 million and $16.4 million, respectively. The tax benefit realized for the tax deduction from stock options exercised during 2015, 2014 and 2013 totaled $6.5 million, $6.9 million and $7.4 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table summarizes information for outstanding stock options outstanding at December 31, 2015:

			Options Outstanding						Options Exercisable
Range of Exercise Prices			Number Outstanding as of 12/31/2015		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable as of 12/31/2015		Weighted Average Exercise Price
$21.96	-	$46.78		422,092		6.89	$	43.85		204,584	$	43.36
$49.33	-	$49.33		167,206		6.00	$	49.33		119,464	$	49.33
$58.54	-	$58.54		180,883		8.07	$	58.54		46,220	$	58.54
$21.96	-	$58.54		770,181		6.97	$	48.49		370,268	$	47.18

Restricted Stock Awards

The following table presents the changes of restricted stock awards and related information for 2015:

	Number of Awards			Weighted Average Grant Date Fair Value Per Share
Nonvested shares at January 1, 2015		1,106,670		$	39.80
Granted		559,207			42.39
Vested		(446,506	)		42.44
Forfeited		(47,487	)		46.77
Nonvested shares at December 31, 2015		1,171,884		$	43.08

During 2015, we granted restricted stock awards totaling 559,207 shares valued at a total of $23.7 million. Of the restricted stock awards granted in 2015, 461,658 awards vest in four equal annual installments beginning in February 2016, 75,900 awards are performance-based awards that may (but currently appear unlikely to) vest in February 2018 in an amount that will depend on the Company’s achievement of specified performance objectives, 20,062 awards are for director compensation and vest 100% in May 2016, and 1,587 awards (also for director compensation) vested 100% immediately. The 2015 performance-based awards (75,900 shares at target performance level) with three-year cliff vesting have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period commencing January 1, 2015 and ending December 31, 2017.

The weighted average grant date fair value per share for restricted stock awards granted in 2015, 2014 and 2013 was $42.39, $93.09 and $82.05, respectively. The total fair value of restricted stock awards vested in 2015, 2014 and 2013 was $18.9 million, $27.2 million and $18.7 million, respectively. As of December 31, 2015, there was $29.3 million of total compensation costs related to nonvested restricted stock awards not yet recognized, which is expected to be recognized over a weighted average period of 2 years.

At December 31, 2015, a total of 1,837,279 shares were available for future grant under the Equity Participation Plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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 (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, 2015, Trust assets totaled $16.9 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, 2015, including the fair value of the shares of the Company's common stock that are reflected as treasury stock, was $17.0 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.

In accordance with current accounting standards, all fair value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of income. Increases or decreases in the fair value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of income. In response to the changes in total fair value of the Company's common stock held by the Trust, the Company recorded net compensation expense adjustments to the liability of $(0.2) million in 2015, less than $0.1 million in 2014 and $0.5 million in 2013.

16. Segment and Related Information

In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments from continuing operations: 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. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. 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, 2015, 2014 and 2013, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

	Revenues from unaffiliated customers		Depreciation and amortization		Operating income (loss)			Equity in income (losses) of unconsolidated affiliates			Capital expenditures		Total assets
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 and eliminations		--		1,340		(47,237	)		--			690		40,099
Total	$	1,099,977	$	131,257	$	55,006		$	526		$	114,738	$	1,599,138

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 and eliminations		--		1,023		(68,204	)		--			2,054		48,669
Total	$	1,819,609	$	124,776	$	310,255		$	378		$	199,256	$	1,809,612

2013
Well site services -
Completion services	$	576,040	$	65,644	$	127,280		$	--		$	95,236	$	589,626
Drilling services		170,467		24,908		22,363			--			25,535		139,973
Total well site services		746,507		90,552		149,643			--			120,771		729,599
Offshore products		882,627		17,751		156,918			(355	)		42,694		940,825
Corporate and eliminations		--		928		(59,284	)		--			1,430		338,435
Total	$	1,629,134	$	109,231	$	247,277		$	(355	)	$	164,895	$	2,008,859

Financial information by geographic segment for each of the three years ended December 31, 2015, 2014 and 2013, is summarized below in thousands. Revenues in the United States include export sales. Revenues are attributable to countries based on the location of the entity selling the products or performing the services. Total assets are attributable to countries based on the physical location of the entity and its operating assets and do not include intercompany balances.

	United States		United Kingdom		Singapore		Other Non U.S.		Total
2015
Revenues from unaffiliated customers	$	797,762	$	170,536	$	66,305	$	65,374	$	1,099,977
Long-lived assets		820,464		74,082		26,462		66,619		987,627
2014
Revenues from unaffiliated customers	$	1,468,202	$	188,753	$	83,493	$	79,161	$	1,819,609
Long-lived assets		826,648		54,868		27,438		71,265		980,219
2013
Revenues from unaffiliated customers	$	1,261,186	$	171,439	$	106,937	$	89,572	$	1,629,134
Long-lived assets		803,918		33,107		25,511		66,239		928,775

No customers accounted for more than 10% of the Company's revenues in the years ended December 31, 2015, 2014 and 2013. Equity in net income of unconsolidated affiliates is not included in operating income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

17. Valuation Allowances

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

	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (net of recoveries)			Translation and Other, Net			Balance at End of Period
Year Ended December 31, 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
Year Ended December 31, 2013:
Allowance for doubtful accounts receivable	$	3,804	$	505	$	(419	)	$	(12	)	$	3,878
Allowance for excess, damaged or obsolete inventory		8,603		2,076		(1,159	)		20			9,540

18. Quarterly Financial Information (Unaudited)

The following table summarizes quarterly financial information for 2015 and 2014 (in thousands, except per share amounts):

	First Quarter⁽²⁾		Second Quarter⁽³⁾			Third Quarter⁽⁴⁾			Fourth Quarter⁽⁵⁾
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		--		--			--			--

2014
Revenues	$	405,237	$	459,607		$	471,032		$	483,733
Gross profit⁽¹⁾		132,866		151,699			164,535			164,626
Net income attributable to:
Continuing operations		34,709		(24,122	)		58,387			58,253
Discontinued operations		36,795		16,242			(1,467	)		206
Basic earnings per share:
Continuing operations		0.65		(0.45	)		1.08			1.10
Discontinued operations		0.68		0.30			(0.03	)		--
Diluted earnings per share:
Continuing operations		0.64		(0.45	)		1.07			1.09
Discontinued operations		0.68		0.30			(0.02	)		--

(1)

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

(2)

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. In the first quarter of 2014, we incurred $1.4 million (pre-tax) of third-party transaction costs in our continuing operations, primarily related to the Spin-Off.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

(3)

In the second quarter of 2015, we recognized $1.7 million (pre-tax) of severance and other downsizing charges. In the second quarter of 2014, we recognized in our continuing operations a pre-tax loss on extinguishment of debt of $100.4 million and $9.6 million (pre-tax) representing transaction costs primarily related to the Spin-Off.

(4)

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)

In the fourth quarter of 2015, we recognized a $3.4 million 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.

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