10-K

Commercial oil and gas fields consist of porous and permeable reservoir rocks that contain natural gas, crude oil and water. Due to the density differences of the fluids, natural gas typically caps the field and overlies an oil layer, which overlies the water. We provide services that characterize the porous reservoir rock and all three reservoir fluids. Services relating to these fluids include determining quality and measuring quantity of the fluids and their derived products. This includes determining the value of different crude oil and natural gases by analyzing the individual components of complex hydrocarbons. These data sets are used by oil companies to determine the most efficient method by which to recover, process and refine these hydrocarbons to produce the maximum value added to crude oil and natural gas.

We analyze samples of reservoir rocks for their porosity, which determines reservoir storage capacity, and for their permeability, which defines the ability of the fluids to flow through the rock. These measurements are used to determine how much oil and gas are present in a reservoir and the rates at which the oil and gas can be produced. We also use our proprietary services and technologies to correlate the reservoir description data to wireline logs and seismic data by determining the different acoustic velocities of reservoir rocks containing water, oil and natural gas. These measurements are used in conjunction with our reservoir management services to develop programs to produce more oil and gas from the reservoir.

We provide diagnostic services and products to help optimize completion and reservoir operations and field development strategies in order to increase recoverable reserves in the most efficient way. Two production enhancement methods commonly used are (i) hydraulic fracturing of the reservoir rock to improve flow and (ii) flooding a reservoir with water, carbon dioxide, nitrogen or hydrocarbon gases to force more oil and gas to the wellbore. Many oilfields today are hydraulically fractured and/or flooded to maximize oil and gas recovery. Although Core Laboratories is not a hydraulic fracturing company, we do provide services that are used by others to develop and optimize hydraulic fracturing and field flood projects and to evaluate the success of those projects. Our services and technologies play a key role in the success of both methods.

The hydraulic fracturing of a producing formation is achieved by pumping a fluid slurry containing a proppant material into the reservoir zone at extremely high pressures. This fractures the rock and the proppant material "props" or holds the fractures open after the pressure pumping is complete so that reservoir fluids can flow to the production wellbore. Our data on rock type and strength are critical for determining the proper design of the hydraulic fracturing job. In addition, our testing indicates whether the fluid slurry is compatible with the reservoir rock so that damage does not occur that would restrict production. We also provide testing of various propping agents and software to help pick the best proppant based on net present value calculations of client investments. Our proprietary and patented ZERO WASH^® tracer technology is used to determine that the proppant material was properly placed in the fracture to ensure effective flow and increased recovery.

Core's patented and proprietary SPECTRACHEM^® fracture diagnostic service continued to evolve with the introduction of the SPECTRACHEM^®Plus service in early 2009. The SPECTRACHEM^®Plus service is effective in determining the effectiveness and efficiency of the hydraulic fracture stimulation of long multi-stage horizontal wells in oil- and gas-shale plays throughout North America and with growing demand internationally as unconventional resource plays are developed globally. SPECTRACHEM^®Plus data sets are used to determine how each frac stage is flowing. Frac stages with ineffective flows may warrant further stimulation, remedial actions and guide improvements on future frac designs.

FLOWPROFILER^TM technology employs a unique hydrocarbon-soluble tracer and water-soluble tracer introduced into specific and isolated stages via the stimulating proppant stream. The hydrocarbon-soluble tracers are absorbed by the crude oil or gas associated with each stage while the water-soluble tracer remains in the stimulation fluid. When the well is flowed, crude oil or gas and water samples are collected and analyzed in the laboratory to identify and quantify oil or gas flows from each stage and the cleanup of the stimulation fluid. Stages not at optimum flow rates can be identified, precipitating remedial efforts to increase flow and recovery rates, and to provide valuable insight for future wells. This service, which we first used more than five years ago, is being used to monitor offset well interference by sampling offset well oil or gas and water production. The amount of tracer detected in offset wells is being used to help our clients optimize both lateral and vertical well spacing and the amount of fracturing fluids for each stage.

In addition to our many patented reservoir analysis technologies, we have established ourselves as a global leader in the manufacture and distribution of high-performance perforating products. Our unique understanding of complex reservoirs supports our ability to supply perforating systems engineered to maximize well productivity by reducing, eliminating and overcoming formation damage caused during the drilling and completion of oil and gas wells. Our "systems" approach to the perforating of an oil or gas well has resulted in numerous patented products. Our HERO^® (High Efficiency Reservoir Optimization), SUPERHERO^® and SUPERHERO^®Plus perforating systems have quickly become industry leaders in enhancing reservoir performance. The SUPERHERO^® and SUPERHERO^®Plus perforating systems complement our successful HERO^® line and are designed to optimize wellbore completions and stimulation programs in oil- and gas-shale reservoirs. Evolved from our HERO^® charges, the SUPERHERO^® and the SUPERHERO^®Plus charges use a proprietary and patented design of powdered metal liners and explosives technology that results in a deeper and cleaner perforating tunnel into the oil- and gas-shale reservoir. This allows greater flow of hydrocarbons to the wellbore and helps to maximize hydrocarbon recovery from the reservoir. Moreover, the deeper, near debris-free perforations enable lower fracture initiation pressures, reducing the amount of pressure-pumping horsepower required and its associated cost. SUPERHERO^® and SUPERHERO^®Plus charges can eliminate the ineffective perforations that would otherwise limit daily oil and natural gas production and hinder the optimal fracture stimulation programs needed for prolific production from the Bakken, Eagle Ford, Marcellus, Niobrara and similar oil- and gas-shale formations. The latest charge development, our HERO Hard Rock or HERO-HR^TM charges, are the deepest

Our Horizontal Time-Delayed Ballistics Actuated Sequential Transfer (HTD-BLAST^TM) perforating system is a technology useful for the effective and efficient perforation of extended-reach horizontal completions in the Bakken, Eagle Ford, and other shale formations. The HTD-BLAST^TM perforating system can be deployed via coiled tubing and currently enables up to 10 perforating events, beginning at the farthest reaches, or toe regions, of extended-reach horizontal wells, or up to 27 perforating events in vertical wellbores. The toe region is the most difficult section of an extended-reach well to effectively perforate and fracture stimulate. The HTD-BLAST^TM system significantly improves the potential for production from those sections. A proprietary, time-delayed detonating sequence allows the operator to position and perforate each of the discrete zones being completed in the toe-end of the wellbore. This efficiency, coupled with Core's effective SUPERHERO^®Plus perforating charges, results in superior perforations at a greatly reduced operating cost. Superior perforations then allow effective fracture stimulation programs that can maximize production from extended horizontal wells.

We have developed KODIAK^TM Enhanced Perforating Systems energetic technology which combines our HERO-HR^TM technology, now API-certified as the industry's deepest penetrating perforating charges, with proprietary accelerator propellant pellets to boost the effectiveness of the perforating/stimulating event. The detonation of the perforating charges initiates a complex, sequentially oxidizing reaction of the propellant pellets, thereby generating a high-pressure pulse of gases, which initiates and propagates fractures into the unconventional reservoir sequence, allowing for cleaner perforation tunnels, improvement of the stimulant/proppant injection, and increased hydrocarbon production.

Reservoir description and production enhancement information, when applied across an entire oilfield or formation, is used to maximize daily production and the ultimate total recovery from the reservoir. We are involved in numerous large-scale reservoir management projects, applying proprietary and state-of-the-art techniques from the earliest phases of a field development program until the last economic barrel of oil is recovered. These projects are of increasing importance to oil companies as the incremental barrel is often the lowest cost and most profitable barrel in the reservoir. Producing incremental barrels increases our clients' cash flows which we believe will result in additional capital expenditures by our clients, and ultimately further opportunities for us. We also develop and provide industry consortium studies to provide critical reservoir information to a broad spectrum of clients in a cost effective manner, such as our multi-client, basin-wide reservoir optimization projects conducted in North America and international settings. Many of these studies examine unconventional reservoirs. An example is our ongoing global shale study that examines the shale potential in Central and Southern Europe, North Africa, India, China and Australia among other regions. Other joint industry projects evaluate the petrophysical, geochemical and production characteristics of North American unconventional plays such as the Eagle Ford shale in South Texas. Conventional studies currently being conducted are a deep water Gulf of Mexico study, a worldwide characterization of tight-gas sands, with special emphasis in the Middle East region, and deepwater studies off the coasts of West Africa and Brazil.

The market for our services and products is characterized by changing technology and frequent product introduction. As a result, our success is dependent upon our ability to develop or acquire new services and products on a cost-effective basis and to introduce them into the marketplace in a timely manner. Many of our acquisitions have allowed us to obtain the benefits of the acquired company's research and development projects without the significant costs that would have been incurred if we had attempted to develop the services and products ourselves. We incur costs as part of internal research and development and these costs are charged to expense as incurred. We intend to continue committing financial resources and effort to the development and acquisition of new services and products. Over the years, we have made a number of technological advances, including the development of key technologies utilized in our operations. Substantially all of the new technologies have resulted from requests and guidance from our clients, particularly major oil companies.

We are subject to stringent governmental laws and regulations, both in the United States and other countries, pertaining to protection of the environment and the manner in which chemicals and gases used in our analytical and manufacturing processes are handled and generated wastes are disposed. Consistent with our quality assurance and control principles, we have established proactive environmental policies for the management of these chemicals and gases as well as the handling, recycling or disposal of wastes resulting from our operations. Compliance with these laws and regulations, whether at the federal, provincial, regional, state or local levels, may require the acquisition of permits to conduct regulated activities, capital expenditures to limit or prevent emissions and discharges, and stringent practices to handle, recycle and dispose of certain wastes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial or corrective obligations, and the issuance of injunctive relief.

*Reduction of Methane and Ozone Emissions. In August 2015, the U.S. Environmental Protection Agency (“EPA”) published a proposed rule under the federal Clean Air Act (“CAA”) that will establish emission standards for methane and volatile organic compounds released from new and modified oil and natural gas production and natural gas processing and transmissions facilities. This rulemaking, which is a 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, is expected to be finalized by the EPA in 2016. More recently, in October 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively.

*Climate Change. A number of state and regional efforts exist that are aimed at tracking or reducing greenhouse gas (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. In addition, the EPA has determined that GHG emissions present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the CAA, and require monitoring and annual reporting of GHG emissions from certain onshore and offshore production facilities and onshore processing, transmission and storage facilities in the petroleum and natural gas system sources. On an international level, the United States is one of almost 200 nations that agreed in December 2015 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 but it is not possible at this time to predict how or when the United State might impose legal requirements as a result of this international agreement.

*Hydraulic Fracturing. Several federal agencies have asserted regulatory authority over aspects of hydraulic fracturing, including the EPA, which proposed rulemakings in April and August 2015 that would establish respective effluent limit guidelines for wastewater from shale natural-gas extraction operations being discharged to a treatment plant and first-time standards to address emissions of methane from hydraulically fractured oil and natural-gas well completions, and the federal Bureau of Land Management (“BLM”), which 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 is being appealed by certain environmental groups. Moreover, the EPA is one of several federal governmental agencies that has conducted or is conducting studies on the environmental aspects of hydraulic fracturing, with the EPA releasing its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded, among other things, that hydraulic fracturing activities have not led 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 the EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from

*Offshore Compliance. In response to the Deepwater Horizon incident in the Gulf of Mexico in 2010, federal governmental agencies under the U.S. Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have pursued, implemented or enforced new rules, Notices to Lessees and Operators (“NTLs”) and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. For example, in September 2015, the BOEM issued draft guidance relating to supplemental bonding procedures that will be released as an NTL and, among other things, eliminate the “waiver” exemption currently allowed by the BOEM with respect to supplemental bonding in favor of a broader self-insurance approach that would allow more operators in federal waters to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount not to exceed 10% of such operators’ tangible net worth.

Our analytical and manufacturing processes involve the handling and use of numerous chemicals and gases as well as the generation of wastes. Spills or releases of these chemicals, gases, and wastes at our facilities, whether by us or prior owners or operators, or at offsite locations where we transport them for recycling or disposal could subject us to environmental liability, either from the applicable government agency or private landowners or other third parties. Such liabilities could be strict, joint and several, as is applicable in the United States under such laws as the federal Comprehensive Environmental Response, Compensation and Liability Act and the federal Resource Conservation and Recovery Act. This could also include costs of cleaning up chemicals and wastes released into the environment and for damages to persons, properties or natural resources. As a result of such actions, we could be required to remove previously disposed wastes (including wastes disposed of or released by prior owners or operators), remediate environmental contamination (including contaminated groundwater), and undertake measures to prevent future contamination. We may not be able to recover some or any of these remedial or corrective costs from insurance. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

Our operations are also subject to stringent governmental laws and regulations, including the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state laws in the United States, whose purpose is to protect the health and safety of workers. In the United States, the OSHA hazard communication standard and applicable community right-to-know regulations require that information is maintained concerning hazardous materials used or produced in our operations and that this information is provided to employees, state and local government authorities, and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The businesses in which we engage are competitive. Some of our competitors are divisions or subsidiaries of companies that are larger and have greater financial and other resources than we have. While no one company competes with us in all of our product and service lines, we face competition in these lines, primarily from independent regional companies and internal divisions of major integrated oil and gas companies. We compete in different product and service lines to various degrees on the basis of price, technical performance, availability, quality and technical support. Our ability to compete successfully depends on elements both within and outside of our control, including successful and timely development of new services and products, performance and quality, client service, pricing, industry trends and general economic trends.

The oil and gas industry is highly cyclical and has been subject to significant economic downturns at various times as a result of numerous factors affecting the supply of and demand for oil and natural gas, including the level of capital expenditures of the oil and gas industry, the level of drilling activity, the level of production activity, market prices of oil and gas, economic conditions existing in the world, interest rates and the cost of capital, environmental regulations, tax policies, political requirements of national governments, coordination by the Organization of Petroleum Exporting Countries ("OPEC"), cost of producing oil and natural gas, and technological advances.

We cannot accurately predict which or what level of our services and products our customers will need in the future. Orders are placed with our suppliers based on forecasts of customer demand and, in some instances, we may establish buffer inventories to accommodate anticipated demand. Our forecasts of customer demand are based on multiple assumptions, each of which may introduce errors into the estimates. In addition, many of our suppliers require a longer lead time to provide products than our customers demand for delivery of our finished products. If we overestimate customer demand, we may allocate resources to the purchase of material or manufactured products that we may not be able to sell when we expect to, if at all. As a result, we would hold excess or obsolete inventory, which would reduce gross margin and adversely affect financial results. Conversely, if we underestimate customer demand or if insufficient manufacturing capacity is available, we would miss revenue opportunities and potentially lose market share and damage our customer relationships. In addition, any future significant cancellations or deferrals of service contracts or product orders could materially and adversely affect profit margins, increase product obsolescence and restrict our ability to fund our operations.

We are subject to the regulations imposed by the FCPA and the ABA, which generally prohibits us and our intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business. In particular, we may be held liable for actions taken by our strategic or local partners even though our partners are not subject to these laws. Any such violations could result in substantial civil and/or criminal penalties and might adversely affect our business, results of operations or financial condition. In addition, our ability to continue to work in these parts of the world discussed above could be adversely affected if we were found to have violated certain laws, including the FCPA and the ABA.

The market for our services and products is characterized by changing technology and product introduction. As a result, our success is dependent upon our ability to develop or acquire new services and products on a cost-effective basis and to introduce them into the marketplace in a timely manner. While we intend to continue committing substantial financial resources and effort to the development of new services and products, we may not be able to successfully differentiate our services and products from those of our competitors. Our clients may not consider our proposed services and products to be of value to them; or if the proposed services and products are of a competitive nature, our clients may not view them as superior to our competitors' services and products. In addition, we may not be able to adapt to evolving markets and technologies, develop new products, or achieve and maintain technological advantages.

Certain of our product lines depend on a limited number of third party suppliers and vendors available in the marketplace. As a result of this concentration in some of our supply chains, our business and operations could be negatively affected if our key suppliers were to experience significant disruptions affecting the price, quality, availability or timely delivery of their products. For example, we have a limited number of vendors for our manufactured product lines. The partial or complete loss of any one of our key suppliers, or a significant adverse change in the relationship with any of these suppliers, through consolidation or otherwise, would limit our ability to manufacture and sell certain of our products.

Our success depends, in part, on our ability to obtain patents, licenses and other intellectual property rights covering our services and products. To that end, we have obtained certain patents and intend to continue to seek patents on some of our inventions, services and products. While we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us. In addition, effective copyright and trade secret protection may be unavailable or limited in certain countries. Litigation, which could demand significant financial and management resources, may be necessary to enforce our patents or other intellectual property rights. Also, there can be no assurance that we can obtain licenses or other rights to necessary intellectual property on acceptable terms.

The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operation.

We are subject to a variety of stringent governmental laws and regulations both in the United States and abroad relating to protection of the environment, occupational health and safety and the use and storage of chemicals and gases used in our analytical and manufacturing processes and the discharge and disposal of wastes generated by those processes. Certain of these laws and regulations may impose joint and several, strict liability for environmental liabilities, such as the remediation of historical contamination or recent spills, and failure to comply with such laws and regulations could result in the assessment of damages, fines and penalties, the imposition of remedial or corrective action obligations or the suspension or cessation of some or all of our operations. These stringent laws and regulations could require us to acquire permits or other authorizations to conduct regulated activities, install and maintain costly equipment and pollution control technologies, impose specific safety and health standards addressing work protection, or to incur costs or liabilities to mitigate or remediate pollution conditions

caused by our operations or attributable to former owners or operators. If we fail to control the use, or adequately restrict the emission or discharge, of hazardous substances or wastes, we could be subject to future material liabilities including remedial obligations. In addition, public interest in the protection of the environment has increased dramatically in recent years with governmental authorities imposing more stringent and restrictive legal requirements. We anticipate that the trend of more expansive and stricter environmental laws and regulations will continue, the occurrence of which may require us to increase our capital expenditures or could result in increased operating expenses.

Due to concern over the risk of climate change, there has been a broad range of proposed or promulgated state, national and international laws focusing on GHG reduction. Regulatory frameworks adopted, or being considered for adoption, to reduce GHG emissions include cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. For example, the European Emissions Trading Scheme is a program through which many of the European Union member states are implementing cap and trade controls covering numerous power stations and industrial facilities. Also, almost 200 nations, including the United States, agreed to an international climate change agreement in Paris, France, in December 2015 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; however, it is not possible at this time to predict how or when such legal requirements might be imposed by these participating countries. These proposed or promulgated laws and legal initiatives apply or could apply in countries where we have interests or may have interests in the future. These requirements could make our services and products more expensive, lengthen project implementation times, and reduce demand for the production of oil and natural gas, which could decrease demand for our services and products. In the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing emissions of GHGs and Congress has from time to time considered legislation to reduce emissions of GHGs but no such legislation has yet been adopted. However, the EPA has determined that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations under existing provisions of the CAA that establish construction and operating permit reviews for GHG emissions from certain large stationary sources that are already potential major sources of criteria pollutant emissions and that require the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources in the United States, which include the operations of many of our exploration and production clients. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions in the United State would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our clients’ operations could require our clients to incur increased costs and also could adversely affect demand for the oil and natural gas that they produce, which could decrease demand for our services and products.

Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. Some countries outside the United States, such as Bulgaria and France, currently have imposed moratoria on hydraulic fracturing while other countries, such as the United Kingdom, allow fracturing activities but those activities are not as widely pursued as they are in the United States. In the United States, the fracturing process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA proposed rulemakings in April and August 2015 that would establish respective effluent limit guidelines for wastewater from shale natural-gas extraction operations being discharged to a treatment plant and first-time standards to address emissions of methane from hydraulically fractured oil and natural-gas well completions. In addition, 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 is being appealed by certain environmental groups. In addition, the United States Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. States could elect to prohibit fracturing altogether, following the lead of the State of New York in 2015. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions related to the hydraulic fracturing process are adopted in areas where our exploration and production clients’ operate, those clients could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand for our products and services. Several federal governmental agencies in the United States are conducting studies on the environmental aspects of hydraulic fracturing activities. In particular, the EPA is pursuing a study on the potential environmental effects of hydraulic fracturing on drinking water sources, releasing its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded, among other things, that hydraulic fracturing activities have not led 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 EPAs 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. These studies, or any future reviews, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing in the United States, which events could delay or curtail production of natural gas by exploration and production operators, some of which are our clients, and thus reduce demand for our products and services.

Our success depends upon attracting and retaining highly skilled professionals and other technical personnel. A number of our employees are highly skilled engineers, geologists and highly trained technicians, and our failure to continue to attract and retain such individuals could adversely affect our ability to compete in the oilfield services industry. We may confront significant and potentially adverse competition for these skilled and technically knowledgeable personnel, particularly during periods of increased demand for oil and gas. Additionally, at times there may be a shortage of skilled and technical personnel available in the market, potentially compounding the difficulty of attracting and retaining these employees. As a result, our business, results of operations and financial condition may be materially adversely affected.

No assurance can be given that we will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our indebtedness, selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure that any refinancing or debt restructuring would be possible or, if possible, would be completed on favorable or acceptable terms, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Disruptions in the capital and credit markets could adversely affect our ability to refinance our indebtedness, including our ability to borrow under our existing revolving credit facility ("Credit Facility"). Banks that are party to our existing Credit Facility may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from us and other borrowers within a short period of time.

Although we are a Netherlands company, our assets are located in a variety of countries. In addition, not all members of our supervisory board of directors are residents of the same countries as other supervisory directors. As a result, it may not be possible for you to effect service of process within certain countries upon our supervisory directors, or to enforce against our supervisory directors or use judgments of courts of certain countries predicated upon civil liabilities under a country's federal securities laws. Because there is no treaty between certain countries and The Netherlands providing for the reciprocal recognition and enforcement of judgments, some countries' judgments are not automatically enforceable in The Netherlands or in the United States, where the principal market for our shares is located. In addition, there is doubt as to whether a court in one country would impose civil liability on us or on the members of our supervisory board of directors in an original action brought against us or our supervisory directors in a court of competent jurisdiction in another country and predicated solely upon the federal securities laws of that other country.

In August 2012, the SEC issued their final rule to implement Section 1502 of the Dodd-Frank Wall Street Reform and Consumer Protection Act regarding mandatory disclosure and reporting requirements by public companies of their use of “conflict minerals” (tantalum, tin, tungsten and gold) and whether these minerals originate in the Democratic Republic of Congo or adjoining countries ("conflict area"). As our suppliers determine the original source of the conflict minerals they sell or use in their manufacturing processes, we may find that sourcing of these conflict minerals from areas outside the conflict area (conflict-free) at competitive prices and availability in sufficient quantities could be affected. If the number of suppliers who provide conflict-free minerals is limited, this could have a material adverse effect on the Company's ability to purchase these conflict-free products or to purchase these conflict-free products at a favorable price or on favorable terms in the future.

Currently, we have over 70 offices (totaling approximately 3.0 million square feet of space) in more than 50 countries. In these locations, we lease approximately 2.0 million square feet and own approximately 1.0 million square feet. We serve our worldwide clients through six Advanced Technology Centers ("ATCs") that are located in Aberdeen, Scotland; Abu Dhabi, UAE; Calgary, Canada; Houston, Texas; Kuala Lumpur, Malaysia; and Rotterdam, The Netherlands. The ATCs provide support for our more than 50 regional specialty centers located throughout the global energy producing provinces. In addition, we have manufacturing facilities located in Godley, Texas, and Red Deer, Alberta, Canada, which are included in our Production Enhancement business segment. Our facilities are adequate for our current operations; however, expansion into new facilities or the replacement or modification of existing facilities may be required to accommodate future growth.

The following performance graph compares the performance of our common shares to the Standard & Poor's 500 Index and the Standard & Poor's Oil & Gas Equipment and Services Index (which has been selected as our peer group) for the period beginning December 31, 2010 and ending December 31, 2015. The graph assumes that the value of the investment in our common shares and each index was $100 at December 31, 2010 and that all dividends were reinvested. The stockholder return set forth below is not necessarily indicative of future performance. The following graph and related information is "furnished" and shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended (the "Exchange Act") except to the extent that Core Laboratories specifically incorporates it by reference into such filing.



	For the Years Ended December 31,
	2015			2014		2013		2012		2011
	(in thousands, except per share and other data)
Financial Statement Data:
Revenue	$	797,520		$	1,085,222	$	1,073,508	$	981,080	$	907,648
Net income attributable to Core Laboratories N.V.	114,847			257,485		242,811		216,071		184,684
Working capital	117,789			169,954		168,093		156,397		143,353
Total assets	625,258			673,325		659,364		634,391		608,276
Long-term debt and capital lease obligations, including current maturities	430,987			353,672		265,382		231,948		222,822
Total equity (deficit)	(23,699		)	93,993		169,389		187,913		181,655

Earnings Per Share Information:
Net income attributable to Core Laboratories N.V.:
Basic	$	2.69		$	5.80	$	5.31	$	4.58	$	3.99
Diluted	$	2.68		$	5.77	$	5.28	$	4.54	$	3.82
Weighted average common shares outstanding:
Basic	42,747			44,362		45,692		47,211		46,286
Diluted	42,908			44,600		45,994		47,553		48,393
Cash dividends declared per common share	$	2.20		$	2.00	$	1.28	$	1.12	$	1.00

Other Data:
Current ratio (1)	1.98:1			2.29:1		2.24:1		2.11:1		2.00:1
Debt to EBITDA ratio (2)	1.94:1			0.89:1		0.67:1		0.67:1		0.72:1
(1) Current ratio is calculated as follows: current assets divided by current liabilities.
(2) Debt to EBITDA ratio is calculated as follows: gross debt less cash divided by the sum of net income plus interest, taxes, depreciation, amortization, severance, and certain non-cash adjustments.

We provide services and design and produce products which enable our clients to evaluate reservoir performance and increase oil and gas recovery from new and existing fields. These services and products are generally in higher demand when our clients are investing capital in their field development programs that are designed to increase productivity from existing fields or when exploring for new fields. Our clients' investment in capital expenditure programs tends to correlate over the longer term to oil and natural gas commodity prices. During periods of higher, stable prices, our clients generally invest more in capital expenditures and, during periods of lower or volatile commodity prices, they tend to invest less. Consequently, the level of capital expenditures by our clients impacts the demand for our services and products.



	2015		2014		2013
Baker Hughes Worldwide Average Rig Count (1)	2,337		3,578		3,412
Baker Hughes U.S. Average Rig Count (1)	977		1,862		1,761

Baker Hughes Worldwide Year-End Rig Count (2)	1,969		3,570		3,478
Baker Hughes U.S. Year-End Rig Count (2)	714		1,882		1,771

Average Crude Oil Price per Barrel WTI (3)	$	48.68	$	93.17	$	97.98
Average Crude Oil Price per Barrel Brent (4)	$	52.30	$	98.97	$	108.56
Average Natural Gas Price per MMBtu (5)	$	2.62	$	4.37	$	3.73

Year-end Crude Oil Price per Barrel WTI (3)	$	37.13	$	53.45	$	98.17
Year-end Crude Oil Price per Barrel Brent (4)	$	36.61	$	55.27	$	109.95
Year-end Natural Gas Price per MMBtu (5)	$	2.28	$	3.14	$	4.31
(1) Twelve month average rig count as reported by Baker Hughes Incorporated - Worldwide Rig Count.
(2) Year-end rig count as reported by Baker Hughes Incorporated - Worldwide Rig Count.
(3) Average daily and year-end West Texas Intermediate crude spot price as reported by the U.S. Energy Information Administration.
(4) Average daily and year-end Europe Brent crude spot price as reported by the U.S. Energy Information Administration.
(5) Average daily and year-end Henry Hub natural gas spot price as reported by the U.S. Energy Information Administration.

Outside of North America, activities associated with the exploration for and production of oil have also decreased from 2014 levels, although not as significantly as the land-based activities in North America. The rig count outside of North America at the end of 2015 was down approximately 17% from the end of 2014 and average rig count decreased by approximately 13%. These reduced international activities have impacted most regions, except the Middle East, where we continued to see sustained activity levels during 2015. Subsequent to year end, the rig count outside of North America has declined almost 5% by the end of January 2016. As with North American land-based activity, we believe international activities will also remain at reduced levels without a meaningful improvement in the current global crude oil prices.



	2015				2014				2013					2015 / 2014		2014 / 2013
Revenue:														% Change
Services	$	611,954	76.7	%	$	780,872	72.0	%	$	765,428		71.3	%	(21.6	)%	2.0	%
Product Sales	185,566		23.3	%	304,350		28.0	%	308,080			28.7	%	(39.0	)%	(1.2	)%
TOTAL REVENUE	797,520		100.0	%	1,085,222		100.0	%	1,073,508			100.0	%	(26.5	)%	1.1	%
OPERATING EXPENSES:
Cost of services* (1)	387,739		63.4	%	449,488		57.6	%	444,963			58.1	%	(13.7	)%	1.0	%
Cost of product sales* (1)	144,913		78.1	%	215,783		70.9	%	218,005			70.8	%	(32.8	)%	(1.0	)%
Total cost of services and product sales	532,652		66.8	%	665,271		61.3	%	662,968			61.8	%	(19.9	)%	0.3	%
General and administrative expenses (1)	49,729		6.2	%	45,655		4.2	%	51,988			4.8	%	8.9	%	(12.2	)%
Depreciation and amortization	27,457		3.4	%	26,696		2.5	%	25,471			2.4	%	2.9	%	4.8	%
Other (income) expense, net	3,669		0.5	%	1,069		0.1	%	(338		)	—	%	NM		NM
Severance and other charges	22,943		2.9	%	—		—	%	—			—	%	NM		NM
OPERATING INCOME	161,070		20.2	%	346,531		31.9	%	333,419			31.1	%	(53.5	)%	3.9	%
Interest expense	12,380		1.6	%	10,600		1.0	%	9,317			0.9	%	16.8	%	13.8	%
Income before income tax expense	148,690		18.6	%	335,931		31.0	%	324,102			30.2	%	(55.7	)%	3.6	%
Income tax expense	33,758		4.2	%	77,305		7.1	%	80,908			7.5	%	(56.3	)%	(4.5	)%
Net income	114,932		14.4	%	258,626		23.8	%	243,194			22.7	%	(55.6	)%	6.3	%
Net income attributable to non-controlling interest	85		—	%	1,141		0.1	%	383			—	%	NM		NM
Net income attributable to Core Laboratories N.V.	$	114,847	14.4	%	$	257,485	23.7	%	$	242,811		22.6	%	(55.4	)%	6.0	%

Diluted earnings per share attributable to Core Laboratories N.V.	$	2.68			$	5.77			$	5.28				(53.6	)%	9.3	%

Diluted weighted average common shares outstanding	42,908				44,600				45,994

*Percentage based on applicable revenue rather than total revenue.
"NM" means not meaningful.
(1) Excludes depreciation.

Services revenue decreased to $612.0 million for 2015 from $780.9 million for 2014 and $765.4 million for 2013. Average prices for WTI and Brent crude oil in 2015 declined almost 50% from 2014, after 2014 also having declined more than 50% from 2013, and as a result, the average global rig count fell by 35% in 2015, primarily driven by decreases in the North American rig count. However, over this same time period, our service revenue was down only 22%, as demand for our analytical, diagnostic, and completion services was less impacted by the significant decrease in drilling activities. Our continued focus on worldwide crude oil related and large natural gas liquefaction projects, especially those related to the development of deepwater fields off West and East Africa and the eastern Mediterranean, prevented services revenue from declining further. The increase in services revenue from 2013 to 2014 was primarily due to growth in our fracture diagnostic services led by our FLOWPROFILER^TM technology along with our continued focus on worldwide crude oil related and large natural gas liquefaction projects, especially those related to the development of deepwater fields off West and East Africa, the eastern Mediterranean region and increased activity in the Gulf of Mexico.

Product sales revenue, which is tied more to demand in North America, decreased to $185.6 million for 2015, from $304.4 million for 2014 and $308.1 million in 2013. Although average rig count for the U.S. and Canada declined 48% during 2015 compared to 2014, our product sales revenue decreased only 39% as our differentiated well completion product sales held up better than the industry activity levels in North America. During 2014, sales increased over 2013 due to continued improvement in sales of newly introduced products using more advanced technology which partially replaced perforating products developed using basic technology. This improved sales revenue mix was a result of increasing market penetration of new technologies such as our new completion systems for optimizing completion and stimulations of horizontal wells, including our HTD-BLAST^TM and KODIAK^TM Enhanced Perforating Systems and our permanent reservoir monitoring systems, primarily in the

Revenue for our Reservoir Description segment decreased to $473.4 million in 2015 compared to $519.0 million in 2014 and $522.3 million in 2013. The decrease in revenues in 2015 is primarily due to the strengthening of the U.S. dollar against certain currencies such as the Euro, Australian dollar, Canadian dollar, British pound, and Russian ruble, in which we invoice a portion of our revenue. This segment's operations continue to work on large-scale, long-term, crude-oil and LNG projects with an emphasis on offshore developments and international markets. We continue to focus on large-scale core analyses and reservoir fluids characterization studies in the Asia-Pacific areas, offshore West and East Africa, the eastern Mediterranean region and the Middle East, including Kuwait and the United Arab Emirates.

Revenue for our Production Enhancement segment decreased to $267.2 million in 2015 compared to $467.6 million in 2014 and $452.4 million in 2013. The revenue decrease of 42.8% in 2015 compared to 2014 was less than the decrease in the U.S. horizontal rig count of 62% during 2015. This significant decrease in North America industry activity reduced demand for our products associated with land-based completion of oil wells in U.S. unconventional developments. The increase in revenue in 2014 compared to 2013 was primarily due to the continued success of Core's FLOWPROFILER^TM service, our new completion diagnostic service for optimizing completions and stimulations of horizontal wells, and our new KODIAK^TM propellant booster coupled with our HERO^TM perforating charges.

Operating income for this segment decreased to $35.0 million in 2015 from $165.2 million in 2014 and $154.7 million in 2013. Operating margins decreased to 13.1% in 2015. The decreases in operating income and operating margin in 2015 compared to 2014 were primarily due to decreased revenue in 2015 and the absorption of our fixed-cost structure over this lower revenue. The increases in operating income and operating margin in 2014 compared to 2013 were primarily driven by increased demand for the Company's proprietary and patented hydraulic fracture and field-flood diagnostic technologies and services such as FLOWPROFILER™, SPECTRACHEM^®, ZERO WASH^®, and SPECTRAFLOOD™ diagnostic tracers in North America and internationally.

Revenue for our Reservoir Management segment decreased to $57 million in 2015 compared to $98.7 million in 2014 and $98.8 million in 2013. The decrease in revenue in 2015 compared to 2014 is primarily due to the decrease of oil commodity prices and, as a result, reduced spending from our oil and gas clients, especially in the Canadian oil sands. We continue to have interest in our existing multi-client reservoir studies such as the Duvernay Shale Project in Canada and the Tight Oil Reservoirs of the Midland Basin study as well as our new joint-industry projects in the Williston Basin targeting the tight oil of the entire Three Forks sections and a study in the Appalachian Basin of the emerging Devonian shales in the liquids window.

We have historically financed our activities through cash on hand, cash flows from operations, bank credit facilities, equity financing and the issuance of debt. Cash flows from operating activities provides the primary source of funds to finance operating needs, capital expenditures and our dividend and share repurchase programs. If necessary, we supplement this cash flow with borrowings under bank credit facilities to finance some capital expenditures and business acquisitions. As we are a Netherlands holding company, we conduct substantially all of our operations through subsidiaries. Our cash availability is largely dependent upon the ability of our subsidiaries to pay cash dividends or otherwise distribute or advance funds to us.

Our financial statements are prepared in conformity with generally accepted accounting principles in the U.S. ("U.S. GAAP" or "GAAP"). We utilize the non-GAAP financial measure of free cash flow to evaluate our cash flows and results of operations. Free cash flow is defined as net cash provided by operating activities (which is the most directly comparable GAAP measure) less cash paid for capital expenditures. Management believes that free cash flow provides useful information to investors regarding the cash that was available in the period that was in excess of our needs to fund our capital expenditures and operating activities. Free cash flow is not a measure of operating performance under GAAP, and should not be considered in isolation nor construed as an alternative to operating profit, net income (loss) or cash flows from operating, investing or financing activities, each as determined in accordance with GAAP. Free cash flow does not represent residual cash available for distribution because we may have other non-discretionary expenditures that are not deducted from the measure. Moreover, since free cash flow is not a measure determined in accordance with GAAP and thus is susceptible to varying interpretations and calculations, free cash flow, as presented, may not be comparable to similarly titled measures presented by other companies. The following table reconciles this non-GAAP financial measure to the most directly comparable measure calculated and presented in accordance with U.S. GAAP for the years ended December 31, 2015, 2014 and 2013 (in thousands):

During the year ended December 31, 2015, we repurchased 1,444,534 shares of our common stock for an aggregate amount of $159.7 million, or an average price of $110.56 per share. The repurchase of shares in the open market is at the discretion of management pursuant to shareholder authorization. We regard these treasury shares as a temporary investment which may be used to fund restricted shares that vest or to finance future acquisitions. Under Dutch law and subject to certain Dutch statutory provisions and shareholder approval, we can hold a maximum of 50% of our issued shares in treasury. We currently have shareholder approval to hold 10% of our issued share capital in treasury. On May 21, 2015 at our annual shareholders meeting, our shareholders authorized the extension of our share repurchase program until November 21, 2016 to purchase up to 10% of our issued share capital. We believe this share repurchase program has been beneficial to our shareholders. Our share price has increased from $4.03 per share in 2002, when we began to repurchase shares, to $108.74 per share on December 31, 2015, an increase of over 2,598%.

The terms of the Credit Facility and Senior Notes require us to meet certain covenants, including, but not limited to, an interest coverage ratio (consolidated EBITDA divided by interest expense) and a leverage ratio (consolidated net indebtedness divided by consolidated EBITDA), where consolidated EBITDA (as defined in each agreement) and interest expense are calculated using the most recent four fiscal quarters. The Credit Facility has the more restrictive covenants with a minimum interest coverage ratio of 3.0 to 1.0 and a maximum leverage ratio of 2.5 to 1.0. We believe that we are in compliance with all such covenants contained in our credit agreements. Certain of our material, wholly-owned subsidiaries are guarantors or co-borrowers under the Credit Facility and Senior Notes.

In 2014, we entered into two interest rate swap agreements for a total notional amount of $50 million to hedge changes in the variable rate interest expense on $50 million of our existing or replacement LIBOR-priced debt. Under the first swap agreement of $25 million, we fixed the LIBOR portion of the interest rate at 1.73% through August 29, 2019, and under the second swap agreement of $25 million, we fixed the LIBOR portion of the interest rate at 2.50% through August 29, 2024. Each swap is measured at fair value and recorded in our consolidated balance sheet as a liability. They are designated and qualify as cash flow hedging instruments and are highly effective. Unrealized losses are deferred to shareholders' equity as a component of accumulated other comprehensive loss (AOCL) and are recognized in income as an increase to interest expense in the period in which the related cash flows being hedged are recognized in expense.



	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 Years
Contractual Obligations:
Debt (1)	$	433,000	$	—	$	—	$	283,000	$	150,000
Other indebtedness	2,244		2,244		—		—		—
Operating leases	66,985		15,565		21,598		11,163		18,659
Pension (2)	1,793		1,793		—		—		—
Total contractual obligations	$	504,022	$	19,602	$	21,598	$	294,163	$	168,659

(1) Not included in the above balances are anticipated cash payments for interest of $6.1 million a year for 2016-2021 and cash payments for interest of $3.1 million a year for 2022-2023 for a total of $42.8 million.
(2) Our Dutch pension plan requires annual employer contributions. Amounts payable in the future will be based on future workforce factors which cannot be projected beyond one year.

We expect our investment in capital expenditures to track client demand for our services and products. Given the current downward trend in industry activity levels, we have not determined, at this time, the level of investment that will be made in 2016. We will, however, continue to invest to fund the purchase of instrumentation, tools and equipment along with expenditures to replace obsolete or worn-out instrumentation, tools and equipment, to consolidate certain facilities to gain operational efficiencies, and to increase our presence where requested by our clients. In addition, we plan to continue to (i) repurchase our common shares on the open market through our share repurchase program, (ii) pay a dividend and (iii) if

Our ability to maintain and increase our operating income and cash flows is largely dependent upon continued investing activities. We are a Netherlands holding company and substantially all of our operations are conducted through subsidiaries. Consequently, our cash flow depends upon the ability of our subsidiaries to pay cash dividends or otherwise distribute or advance funds to us. We believe our future cash flows from operating activities, supplemented by our borrowing capacity under existing facilities and our ability to issue additional equity should be sufficient to meet our contractual obligations, capital expenditures, working capital needs, dividend payments, debt requirements and to finance future acquisitions.

The preparation of financial statements in accordance with U.S. GAAP requires us to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. We evaluate our estimates on an ongoing basis and determine the adequacy of our estimates based on our historical experience and various other assumptions that we believe are reasonable under the circumstances. By nature, these judgments are subject to an inherent degree of uncertainty. We consider an accounting estimate to be critical if it is highly subjective and if changes in the estimate under different assumptions would result in a material impact on our financial condition and results of operations. The following transaction types require significant judgment and, therefore, are considered critical accounting policies as of December 31, 2015.

We evaluate whether client receivables are collectible. We perform ongoing credit evaluations of our clients and monitor collections and payments in order to maintain a provision for estimated uncollectible accounts based on our historical collection experience and our current aging of client receivables outstanding in addition to clients' representations and our understanding of the economic environment in which our clients operate. Based on our review, we establish or adjust allowances for specific clients and the accounts receivable as a whole. Our allowance for doubtful accounts increased to $4.1 million as of December 31, 2015, compared to $3.4 million as of December 31, 2014.

Our income tax expense includes income taxes of The Netherlands, the U.S. and other foreign countries as well as local, state and provincial income taxes. We recognize deferred tax assets or liabilities for the differences between the financial statement carrying amount and tax basis of assets and liabilities using enacted tax rates in effect for the years in which the asset is recovered or the liability is settled. We estimate the likelihood of the recoverability of our deferred tax assets (particularly, net operating loss carry-forwards). Any valuation allowance recorded is based on estimates and assumptions of taxable income into the future and a determination is made of the magnitude of deferred tax assets which are more likely than not to be realized. Valuation allowances of our net deferred tax assets aggregated to $10.9 million and $7.2 million at December 31, 2015 and 2014, respectively. If these estimates and related assumptions change in the future, we may be required to record additional valuation allowances against our deferred tax assets and our effective tax rate may increase which could result in a material adverse effect on our financial position, results of operations and cash flows. We have not provided for deferred taxes on the

Property, plant and equipment are carried at cost less accumulated depreciation. Major renewals and improvements are capitalized while maintenance and repair costs are charged to expense as incurred. They are depreciated using the straight-line method based on their individual estimated useful lives, except for leasehold improvements, which are depreciated over the remaining lease term, if shorter. We estimate the useful lives and salvage values of our assets based on historical data of similar assets. When long-lived assets are sold or retired, the remaining costs and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in income. These capitalized long-lived assets could become impaired if our operating plans or business environment changes.

We evaluated our goodwill for impairment by comparing the fair value of each of our reporting units, which are our reportable segments, to their net carrying value as of the balance sheet date. We estimated the fair value of each reporting unit using a discounted future cash flow analysis. Estimated future cash flows were based on the company's best estimate of future performance. Our impairment analysis is quantitative; however, it includes subjective estimates based on assumptions regarding future growth rates, interest rates and operating expenses. If the carrying value of the reporting unit exceeds the fair value determined, an impairment loss is recorded to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value. We did not record impairment charges relating to our goodwill or our indefinite-lived intangible assets during the years ended December 31, 2015, 2014 and 2013.

value our obligations. We recognize net periodic benefit cost based upon these estimates. As required by current accounting standards, we recognize net periodic pension costs associated with this plan in income from current operations and recognize the unfunded status of the plan, if any, as a long-term liability. In addition, we recognize as a component of other comprehensive income, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic pension cost. See Note 10 of the Notes to Consolidated Financial Statements. Furthermore, we sponsor several defined contribution plans for the benefit of our employees. We expense these contributions in the period the contribution is made.

We have two stock-based compensation plans, as described in further detail in Note 13 of the Notes to Consolidated Financial Statements. We evaluate the probability that certain of our stock-based plans will meet targets established within the respective agreements and result in the vesting of such awards. In addition, we derive an estimated forfeiture rate that is used in calculating the expense for these awards. For new awards issued and awards modified, repurchased or canceled, the compensation expense is equal to the fair value of the award at the date of the grant and is recognized in the Consolidated Statement of Operations for those awards earned over the requisite service period of the award. The fair value is determined by calculating the discounted value of the shares over the vesting period and applying an estimated forfeiture rate.

This Form 10-K and the documents incorporated in this Form 10-K by reference contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These "forward-looking statements" are based on an analysis of currently available competitive, financial and economic data and our operating plans. They are inherently uncertain and investors should recognize that events and actual results could turn out to be significantly different from our expectations. By way of illustration, when used in this document, words such as "anticipate", "believe", "expect", "intend", "estimate", "project", "will", "should", "could", "may", "predict" and similar expressions are intended to identify forward-looking statements. You are cautioned that actual results could differ materially from those anticipated in forward-looking statements. Any forward-looking statements, including statements regarding the intent, belief or current expectations of us or our management, are not guarantees of future performance and involve risks, uncertainties and assumptions about us and the industry in which we operate, including, among other things:

In May 2015, the FASB issued ASU 2015-03 ("Simplifying the Presentation of Debt Issuance Costs") to simplify the presentation of debt issuance costs. The amendments in this update require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. This pronouncement is effective for public business entities for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early adoption of the amendments in ASU 2015-03 is permitted for financial statements that have not been previously issued. We have chosen to adopt this standard early for the fiscal year ended December 31, 2015. The adoption of this standard resulted in a reclassification of the debt issuance costs of $2.0 million and $2.3 million for the years ended December 31, 2015 and 2014, respectively, from Other assets to Long-term debt on the Consolidated Balance Sheet. There was no impact to the Consolidated Statements of Operations or the Consolidated Statement of Cash Flows.

In May 2014, the FASB issued ASU 2014-09 ("Revenue from Contracts with Customers"), which provides guidance on revenue recognition. The core principle of this guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance requires entities to apply a five-step method to (1) identify the contract(s) with customers; (2) identify the performance obligation(s) in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation(s) in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 (on July 9, 2015, the FASB deferred the implementation date for one year). We are evaluating the impact this standard will have on our consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02 ("Amendments to the Consolidation Analysis"), which affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, the amendments: (1) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities; (2) eliminate the presumption that a general partner should consolidate a limited partnership; (3) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships; and (4) provide a scope exception from consolidation guidance for reporting entities with interest in legal entities that are required to comply with or operate in accordance with requirements that are similar to those for registered money market funds. This pronouncement is effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. This standard will not have a material impact on our consolidated financial statements.

In November 2015, the FASB issued ASU 2015-17 ("Balance Sheet Classification of Deferred Taxes") to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This pronouncement is effective for public business entities for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2016. This standard will have no effect on our Consolidated Statements of Operations and Consolidated Statement of Cash Flows but will have a minor effect on the consolidated balance sheet with the reclassification of certain deferred tax balance sheet accounts.

In 2014, we entered into two interest rate swap agreements for a total notional amount of $50 million to hedge changes in the variable rate interest expense on $50 million of our existing or replacement LIBOR-priced debt. Under the first swap agreement of $25 million, we have fixed the LIBOR portion of the interest rate at 1.73% through August 29, 2019, and under the second swap agreement of $25 million, we have fixed the LIBOR portion of the interest rate at 2.50% through August 29, 2024. Each swap is measured at fair value and recorded in our consolidated balance sheet as a liability. They are designated and qualify as cash flow hedging instruments and are highly effective. Unrealized losses are deferred to shareholders' equity as a component of accumulated other comprehensive loss (AOCL) and are recognized in income as an increase to interest expense in the period in which the related cash flows being hedged are recognized in expense.

We operate in a number of international areas which exposes us to foreign currency exchange rate risk. We do not currently hold or issue forward exchange contracts or other derivative instruments for hedging or speculative purposes (a foreign exchange contract is an agreement to exchange different currencies at a given date and at a specified rate). Foreign exchange gains and losses are the result of fluctuations in the U.S. dollar ("USD") against foreign currencies and are included in other (income) expense in the statements of operations. We recognized foreign exchange losses in countries where the USD weakened against the local currency and we had net monetary liabilities denominated in the local currency, as well as in countries where the USD strengthened against the local currency and we had net monetary assets denominated in the local currency. We recognized foreign exchange gains in countries where the USD strengthened against the local currency and we had net monetary liabilities denominated in the local currency, as well as in countries where the USD weakened against the local currency and we had net monetary assets denominated in the local currency.

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is accumulated and communicated to 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 Securities and Exchange Commission. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2015 at the reasonable assurance level.



Signature		Title

/s/ DAVID M. DEMSHUR		President, Chief Executive Officer,
David M. Demshur		Chairman and Supervisory Director

/s/ RICHARD L. BERGMARK		Executive Vice President,
Richard L. Bergmark		Chief Financial Officer and
		Supervisory Director

/s/ CHRIS S. HILL		Vice President and
Chris S. Hill		Chief Accounting Officer

/s/ CHARLES L. DUNLAP		Supervisory Director
Charles L. Dunlap

/s/ MICHAEL C. KEARNEY		Supervisory Director
Michael C. Kearney

/s/ D. JOHN OGREN		Supervisory Director
D. John Ogren

/s/ JAN WILLEM SODDERLAND		Supervisory Director
Jan Willem Sodderland

/s/ LUCIA VAN GEUNS		Supervisory Director
Lucia van Geuns

/s/ MARGARET ANN VAN KEMPEN		Supervisory Director
Margaret Ann van Kempen

In our opinion, the consolidated financial statements listed in the index appearing under Item 15 (a)(1) present fairly, in all material respects, the financial position of Core Laboratories N.V. (a Netherlands corporation) and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 (a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,2015 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and the financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.



	2015			2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	22,494		$	23,350
Accounts receivable, net of allowance for doubtful accounts of $4,136 and $3,397 at 2015 and 2014, respectively	145,689			197,163
Inventories	40,906			43,371
Prepaid expenses	12,053			14,246
Income tax receivable	7,209			10,980
Other current assets	10,196			12,710
TOTAL CURRENT ASSETS	238,547			301,820
PROPERTY, PLANT AND EQUIPMENT, net	143,211			149,014
INTANGIBLES, net	10,041			10,642
GOODWILL	178,159			164,464
DEFERRED TAX ASSETS, net	11,693			3,876
OTHER ASSETS	43,607			43,509
TOTAL ASSETS	$	625,258		$	673,325
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	33,474		$	47,084
Accrued payroll and related costs	36,475			34,617
Taxes other than payroll and income	9,495			11,199
Unearned revenues	14,101			11,009
Income taxes payable	1,733			8,333
Other current liabilities	25,480			19,624
TOTAL CURRENT LIABILITIES	120,758			131,866
LONG-TERM DEBT, net	430,987			353,672
DEFERRED COMPENSATION	43,478			42,705
DEFERRED TAX LIABILITIES, net	4,881			7,210
OTHER LONG-TERM LIABILITIES	48,853			43,879
COMMITMENTS AND CONTINGENCIES

EQUITY (DEFICIT):
Preference shares, EUR 0.02 par value; 6,000,000 shares authorized, none issued or outstanding	—			—
Common shares, EUR 0.02 par value; 200,000,000 shares authorized, 44,350,002 issued and 42,375,905 outstanding at 2015 and 45,600,002 issued and 43,636,984 outstanding at 2014	1,142			1,174
Additional paid-in capital	—			—
Retained earnings	219,207			415,906
Accumulated other comprehensive income (loss)	(10,538		)	(11,894		)
Treasury shares (at cost), 1,974,097 at 2015 and 1,963,018 at 2014	(238,875		)	(317,613		)
Total Core Laboratories N.V. shareholders' equity (deficit)	(29,064		)	87,573
Non-controlling interest	5,365			6,420
TOTAL EQUITY (DEFICIT)	(23,699		)	93,993
TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	625,258		$	673,325



	2015		2014		2013
REVENUE:
Services	$	611,954	$	780,872	$	765,428
Product sales	185,566		304,350		308,080
Total Revenue	797,520		1,085,222		1,073,508
OPERATING EXPENSES:
Cost of services, exclusive of depreciation shown below	387,739		449,488		444,963
Cost of product sales, exclusive of depreciation shown below	144,913		215,783		218,005
General and administrative expenses, exclusive of depreciation shown below	49,729		45,655		51,988
Depreciation	26,545		25,297		24,168
Amortization	912		1,399		1,303
Other (income) expense, net	3,669		1,069		(338		)
Severance and other charges	22,943		—		—
OPERATING INCOME	161,070		346,531		333,419
Interest expense	12,380		10,600		9,317
Income before income tax expense	148,690		335,931		324,102
Income tax expense	33,758		77,305		80,908
Net income	114,932		258,626		243,194
Net income attributable to non-controlling interest	85		1,141		383
Net income attributable to Core Laboratories N.V.	$	114,847	$	257,485	$	242,811
EARNINGS PER SHARE INFORMATION:
Basic earnings per share attributable to Core Laboratories N.V.	$	2.69	$	5.80	$	5.31
Diluted earnings per share attributable to Core Laboratories N.V.	$	2.68	$	5.77	$	5.28
Cash dividends per share	$	2.20	$	2.00	$	1.28
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	42,747		44,362		45,692
Diluted	42,908		44,600		45,994



	2015			2014			2013
Net income	$	114,932		$	258,626		$	243,194
Other comprehensive income:
Derivatives
Changes in fair value of interest rate swaps	(1,471		)	(1,327		)	—
Interest rate swap amounts reclassified to interest expense	971			245			—
Income taxes on derivatives	583			—			—
Total derivatives	83			(1,082		)	—
Pension and other postretirement benefit plans
Adjustment of unrecognized pension actuarial gain (loss)	1,151			(4,399		)	(1,407		)
Prior service credit arising during period	—			1,024			583
Prior service cost
Amortization to net income of transition asset	(96		)	(87		)	(87		)
Amortization to net income of prior service cost	(85		)	7			159
Amortization to net income of actuarial loss	727			540			468
Income taxes on pension and other postretirement benefit plans	(424		)	729			71
Total pension and other postretirement benefit plans	122			1,189			611
Total other comprehensive income (loss)	1,356			(3,268		)	(213		)
Comprehensive income	116,288			255,358			242,981
Comprehensive income attributable to non-controlling interests	85			1,141			383
Comprehensive income attributable to Core Laboratories N.V.	$	116,203		$	254,217		$	242,598



												Accumulated
	Common Shares					Additional						Other			Treasury Stock					Non-
	Number of		Par			Paid-In			Retained			Comprehensive			Number of					Controlling		Total
	Shares		Value			Capital			Earnings			Income (Loss)			Shares		Amount			Interest		Equity
BALANCE, December 31, 2012	47,899,584		$	1,233		$	—		$	361,255		$	(8,413	)	1,550,173		$	(171,845	)	$	5,683	$	187,913
Stock options exercised, net of capital taxes	—		—			(1,411		)	—			—			(12,000	)	1,494			—		83
Stock-based compensation, net of awards issued	—		—			1,047			(5,509		)	—			(222,176	)	24,988			—		20,526
Tax benefit of stock-based awards issued	—		—			3,744			—			—			—		—			—		3,744
Repurchases of common shares	—		—			—			—			—			1,482,198		(227,216		)	—		(227,216		)
Dividends paid	—		—			—			(58,642		)	—			—		—			—		(58,642		)
Cancellation of treasury shares	(1,149,582	)	(30		)	(3,380		)	(123,985		)	—			(1,149,582	)	127,395			—		—
Other comprehensive income	—		—			—			—			(213		)	—		—			—		(213		)
Net income (loss)	—		—			—			242,811			—			—		—			383		243,194
BALANCE, December 31, 2013	46,750,002		$	1,203		$	—		$	415,930		$	(8,626	)	1,648,613		$	(245,184	)	$	6,066	$	169,389



Stock-based compensation, net of awards issued	—		—			1,295			(12,683		)	—			(216,395	)	31,858			—			20,470
Tax benefit of stock-based awards issued	—		—			3,020			—			—			—		—			—			3,020
Repurchases of common shares	—		—			—			—			—			1,680,800		(264,368		)	—			(264,368		)
Dividends paid	—		—			—			(89,089		)	—			—		—			—			(89,089		)
Cancellation of treasury shares	(1,150,000	)	(29		)	(4,315		)	(155,737		)	—			(1,150,000	)	160,081			—			—
Non-controlling interest dividend	—		—			—			—			—			—		—			(787		)	(787		)
Other comprehensive income	—		—			—			—			(3,268		)	—		—			—			(3,268		)
Net income (loss)	—		—			—			257,485			—			—		—			1,141			258,626
BALANCE, December 31, 2014	45,600,002		$	1,174		$	—		$	415,906		$	(11,894	)	1,963,018		$	(317,613	)	$	6,420		$	93,993
Stock-based compensation, net of awards issued	—		—			3,267			(11,044		)	—			(183,455	)	29,056			—			21,279
Tax benefit of stock-based awards issued	—		—			(175		)	—			—			—		—			—			(175		)
Repurchases of common shares	—		—			—			—			—			1,444,534		(159,709		)	—			(159,709		)
Dividends paid	—		—			—			(94,235		)	—			—		—			—			(94,235		)
Cancellation of treasury shares	(1,250,000	)	(32		)	(3,092		)	(206,267		)	—			(1,250,000	)	209,391			—			—
Non-controlling interest dividend	—		—			—			—			—			—		—			(1,140		)	(1,140		)
Other comprehensive income	—		—			—			—			1,356			—		—			—			1,356
Net income (loss)	—		—			—			114,847			—			—		—			85			114,932
BALANCE, December 31, 2015	44,350,002		$	1,142		$	—		$	219,207		$	(10,538	)	1,974,097		$	(238,875	)	$	5,365		$	(23,699	)

(In thousands)



	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	114,932		$	258,626		$	243,194
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation	21,279			20,470			20,526
Depreciation and amortization	27,457			26,696			25,471
Non-cash interest expense	702			445			480
(Increase) decrease in value of life insurance policies	909			(1,581		)	(5,112		)
Deferred income taxes	(107		)	4,682			6,790
Asset impairments	5,199			—			—
Net (recovery) provision for doubtful accounts	2,592			1,243			(236		)
Other non-cash items	(860		)	(466		)	473
Changes in assets and liabilities, net of effects of acquisitions:
Accounts receivable	49,261			3,486			(16,312		)
Inventories	3,049			2,894			1,291
Prepaid expenses and other current assets	7,744			(10,088		)	13,915
Other assets	2,652			680			(867		)
Accounts payable	(13,353		)	(3,021		)	(6,339		)
Accrued expenses	(9,723		)	(2,611		)	5,979
Other long-term liabilities	4,275			1,873			11,865
Unearned revenue	3,092			121			(2,981		)
Net cash provided by operating activities	219,100			303,449			298,137
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(22,797		)	(36,586		)	(35,416		)
Patents and other intangibles	(1,460		)	(854		)	(3,530		)
Acquisitions, net of cash acquired	(13,774		)	(1,200		)	—
Investment in non-consolidated affiliates	—			—			(98		)
Proceeds from sale of assets	1,320			884			1,036
Proceeds from insurance recovery	—			—			1,385
Premiums on life insurance	(2,943		)	(4,310		)	(6,575		)
Net cash used in investing activities	(39,654		)	(42,066		)	(43,198		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of debt borrowings	(139,656		)	(128,162		)	(134,046		)
Proceeds from debt borrowings	215,000			217,000			167,000
Stock options exercised	—			—			83
Excess tax benefits from stock-based payments	(175		)	3,020			3,744
Debt financing costs	(387		)	(1,128		)	—
Non-controlling interest - dividend	(1,140		)	(394		)	—
Dividends paid	(94,235		)	(89,089		)	(58,642		)
Repurchase of common shares	(159,709		)	(264,368		)	(227,216		)
Net cash used in financing activities	(180,302		)	(263,121		)	(249,077		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(856		)	(1,738		)	5,862
CASH AND CASH EQUIVALENTS, beginning of year	23,350			25,088			19,226
CASH AND CASH EQUIVALENTS, end of year	$	22,494		$	23,350		$	25,088

The accompanying Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the U.S. ("U.S. GAAP" or "GAAP"), and include the accounts of Core Laboratories and its subsidiaries for which we have a controlling voting interest and/or a controlling financial interest. The equity method of accounting is used to record our interest in investments in which we have less than a majority interest and do not exercise control but do exert significant influence. We use the cost method to record certain other investments in which we own less than 20% of the outstanding equity and do not exercise control or exert significant influence. We record non-controlling interest associated with consolidated subsidiaries that are less than 100% owned. All inter-company transactions and balances have been eliminated in consolidation.

Our financial instruments that potentially subject us to concentrations of credit risk relate primarily to cash and cash equivalents and trade accounts receivable. All cash and cash equivalents are on deposit at commercial banks or investment firms with significant financial resources. Our trade receivables are with a variety of domestic, international and national oil and gas companies. We had no clients who provided more than 10% of our revenue for the years ended December 31, 2015, 2014 and 2013. We consider our credit risk related to trade accounts receivable to be limited due to the creditworthiness and financial resources of our clients. We evaluate our estimate of the allowance for doubtful accounts on an on-going basis throughout the year.

Trade accounts receivable are recorded at their invoiced amounts and do not bear interest. We perform ongoing credit evaluations of our clients and monitor collections and payments in order to maintain a provision for estimated uncollectible accounts based on our historical collection experience and our current aging of client receivables outstanding, in addition to client's representations and our understanding of the economic environment in which our clients operate. Based on our review we establish or adjust allowances for specific clients and the accounts receivable as a whole, and recognize expense. When an account is determined to be uncollectible, we charge the receivable to our allowance for doubtful accounts. Our allowance for doubtful accounts totaled $4.1 million and $3.4 million at December 31, 2015 and 2014, respectively. The net carrying value of accounts receivable is considered to be representative of its respective fair value.

We evaluated our goodwill for impairment by comparing the fair value of each of our reporting units, which are our reportable segments, to their net carrying value as of the balance sheet date. We estimated the fair value of each reporting unit using a discounted future cash flow analysis. Estimated future cash flows were based on the Company's best estimate of future performance. Our impairment analysis is quantitative; however, it includes subjective estimates based on assumptions regarding future growth rates, interest rates and operating expenses. If the carrying value of the reporting unit exceeds the fair value determined, an impairment loss is recorded to the extent that the implied fair value of the goodwill of the reporting unit is less than its carrying value. Any subsequent impairment loss could result in a material adverse effect upon our financial position and results of operations. We did not record impairment charges relating to our goodwill or our indefinite-lived intangible assets during the years ended December 31, 2015, 2014 or 2013.

Services Revenue: We provide a variety of services to clients in the oil and gas industry. Where services are provided related to the testing and analysis of rock and fluids, we recognize revenue upon the provision of the test results or analysis to the client. For our design, field engineering and completion diagnostic services, we recognize revenue upon the delivery of those services at the well site. In the case of our consortium studies, revenue is recognized when the reservoir model solution is presented to our clients. We conduct testing and provide analysis services in support of our consortium studies recognizing revenue as the testing and analysis results are made available to our consortium members.

Our functional currency is the U.S. Dollar ("USD"). All inter-company financing, transactions and cash flows of our subsidiaries are transacted in USD. Our foreign entities remeasure monetary assets and liabilities to USD at year-end exchange rates, while non-monetary items are measured at historical rates. Revenue and expenses are remeasured at the applicable month-end rate, except for depreciation, amortization and certain components of cost of sales, which are measured at historical rates. For the year ended December 31, 2015, we incurred a net remeasurement loss of approximately $4.5 million, while in the year ended December 31, 2014, we incurred a net remeasurement loss of approximately $4.2 million, and a net remeasurement loss of approximately $4.3 million in the year ended December 31, 2013. These amounts were included in Other (Income) Expense, net in the accompanying Consolidated Statements of Operations.

We maintain a non-contributory defined benefit pension plan for substantially all of our Dutch employees ("Dutch Plan") who were hired prior to 2007 based on years of service and final pay or career average pay, depending on when the employee began participating. As required by current accounting standards, we recognize net periodic pension costs associated with this plan in income from current operations and recognize the unfunded status of the plan, if any, as a long-term liability. In addition, we recognize as a component of other comprehensive income, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic pension cost. The projection of benefit obligation and fair value of plan assets requires the use of assumptions and estimates. Actual results could differ from those estimates. See Note 10 - Pension and Other Postretirement Benefit Plans. Furthermore, we sponsor several defined contribution plans for the benefit of our employees. We expense these contributions in the period the contribution is made.

Any outstanding balance under the Credit Facility is due August 29, 2019, when the Credit Facility matures. Interest payment terms are variable depending upon the specific type of borrowing under this facility. Our available capacity at any point in time is subject to all terms of the agreements, and is reduced by borrowings outstanding at the time and outstanding letters of credit which totaled $25 million at December 31, 2015, resulting in an available borrowing capacity under the Credit Facility of $92 million. In addition to those items under the Credit Facility, we had $12.3 million of outstanding letters of credit and performance guarantees and bonds from other sources as of December 31, 2015.



	2015			2014
Deferred tax assets:
Net operating loss carry-forwards	$	8,045		$	6,340
Reserves	18,627			14,135
Unrealized benefit plan loss	5,571			4,925
Unrealized foreign exchange	7,994			2,289
Other	3,229			2,232
Total deferred tax assets	43,466			29,921
Valuation allowance (1)	(10,862		)	(7,236		)
Net deferred tax asset	32,604			22,685
Deferred tax liabilities:
Intangibles	(5,876		)	(5,650		)
Property, plant and equipment	(8,372		)	(6,993		)
Accrued interest	(10,111		)	(6,841		)
Unrealized foreign exchange	(6,421		)	—
Other	(1,579		)	(3,498		)
Total deferred tax liabilities	(32,359		)	(22,982		)
Net deferred income taxes	$	245		$	(297	)

	2015			2014
Current deferred tax assets	$	3,164		$	6,130
Current deferred tax liabilities	(9,731		)	(3,093		)
Long-term deferred tax assets	11,693			3,876
Long-term deferred tax liabilities	(4,881		)	(7,210		)
Total deferred tax assets (liabilities)	$	245		$	(297	)

(1) Valuation allowance at 12/31/13 was $6.1 million.

We file income tax returns in the U.S. federal jurisdiction, various states and foreign jurisdictions. We are currently undergoing multiple examinations in various jurisdictions, and the years 1999 through 2014 remain open for examination in various tax jurisdictions in which we operate. In some of these jurisdictions we have received notices of audit assessment that could expose the Company to additional income taxes, including interest and penalty of approximately $17 million in excess of our current estimates. The ultimate settlement and timing of these additional tax assessments is uncertain but the Company will continue to vigorously defend its return filing position and does not view the assessments as probable at this time.

We provide a noncontributory defined benefit pension plan covering substantially all of our Dutch employees ("Dutch Plan") who were hired prior to 2007 based on years of service and final pay or career average pay, depending on when the employee began participating. The benefits earned by the employees are immediately vested. We fund the future obligations of the Dutch Plan by purchasing insurance contracts from a large multi-national insurance company. The insurance contracts are purchased annually and re-new after five years at which time they are replaced with new contracts that are adjusted to include changes in the benefit obligation for the current year and redemption of the expired contracts. We make annual premium payments to the insurance company based on each employee's age and current salary, and the contractual growth rate. We determine the fair value of these plan assets with the assistance of an actuary using observable inputs (Level 2), which approximates the contract value of the investments.



	2015			2014
Projected Benefit Obligation:
Projected benefit obligation at beginning of year	$	59,338		$	49,456
Service cost	1,787			1,445
Interest cost	1,192			1,756
Prior service cost (credit) arising during year	—			(1,024		)
Benefits paid	(982		)	(1,136		)
Administrative expenses	(169		)	(220		)
Actuarial (gain) loss, net	(4,416		)	16,667
Unrealized (gain) loss on foreign exchange	(5,991		)	(7,606		)
Projected benefit obligation at end of year	$	50,759		$	59,338

Fair Value of Plan Assets:
Fair value of plan assets at beginning of year	$	47,528		$	39,504
Increase (decrease) in plan asset value	(2,279		)	13,572
Employer contributions	1,829			1,897
Benefits paid	(982		)	(1,136		)
Administrative expenses	(169		)	(220		)
Unrealized gain (loss) on foreign exchange	(4,811		)	(6,089		)
Fair value of plan assets at end of year	$	41,116		$	47,528

Under-funded status of the plan at end of the year	$	(9,643	)	$	(11,810	)

Accumulated Benefit Obligation	$	43,969		$	50,837

We maintain defined contribution plans (the "Defined Contribution Plans") for the benefit of eligible employees in certain countries, including Canada, The Netherlands, the United Kingdom and the United States. In accordance with the terms of each plan, we and our participating employees contribute up to specified limits, and under certain plans, we may make discretionary contributions in accordance with the terms of the Defined Contribution Plans. For the years ended December 31, 2015, 2014 and 2013, we expensed approximately $6.9 million, $7.9 million and $7.1 million, respectively, for our contributions and our additional discretionary contributions to the Defined Contribution Plans.

compensation plan for employees in the United States (the "Deferred Compensation Plan"), due to certain limitations imposed by the U.S. Internal Revenue Code of 1986, as amended (the "Internal Revenue Code"). The Deferred Compensation Plan also provides for employer contributions to be made on behalf of participants equal in amount to certain forfeitures of, and/or reductions in, employer contributions that participants could have otherwise received under the Defined Contribution Plan for U.S. employees qualified under Internal Revenue Code Section 401(k) had there not been certain limitations imposed by the Internal Revenue Code. Employer contributions to the Deferred Compensation Plan vest ratably over a period of five years. Contributions to the plan are invested in equity and other investment fund assets within life insurance policies, and carried on the balance sheet at fair value. A participant's plan benefits include the participant's deferrals, the vested portion of the employer's contributions, and deemed investment gains and losses on such amounts. The benefits under these contracts are fully vested and payment of benefits generally commences as of the last day of the month following the termination of services except that the payment of benefits for select executives generally commences on the first working day following a six month waiting period following the date of termination. Employer contributions to the Deferred Compensation Plan were $0.3 million for each of the years ended December 31, 2015, 2014 and 2013.

As reported in prior annual filings, in connection with an audit of the 2008 and 2009 U.S. federal income tax returns of our U.S. consolidated group, the U.S. Internal Revenue Service proposed that certain transfer pricing positions taken by the Company be adjusted. On October 26, 2105, Core Laboratories filed a petition with the U.S. Tax Court contesting the IRS proposed deficiencies of approximately $11 million plus interest for this two year audit period. On February 8, 2016, the judge signed and entered a stipulated decision document with the Tax Court, whereby the IRS conceded its position and agreed that the Company does not owe the amount they previously sought in their audit of the Company’s 2008 and 2009 tax years. The Tax Court's decision will be final 90 days from this date.

In connection with our initial public offering in September 1995, our shareholders authorized our Management Board to repurchase up to 10% of our issued share capital, the maximum allowed under Dutch law at the time, for a period of 18 months. This authorization was renewed at subsequent annual or special shareholder meetings. At our annual shareholders' meeting on May 21, 2015, our shareholders authorized an extension to repurchase up to 10% of our issued share capital through November 21, 2016. The repurchase of shares in the open market is at the discretion of management pursuant to this shareholder authorization. From the activation of the share repurchase program on October 29, 2002 through December 31, 2015, pursuant to shareholder approvals, we have repurchased 39,311,745 shares for an aggregate purchase price of approximately $1.6 billion, or an average price of $41.08 per share and have canceled 32,225,406 shares with an historical cost of $1.0 billion. At December 31, 2015, we held 1,974,097 shares in treasury with the authority to repurchase 2,460,903 additional shares under our stock repurchase program. Subsequent to year-end, we have repurchased 270 shares at a total cost of approximately $28.6 thousand.

On May 13, 2014, the 2007 Long-Term Incentive Plan was amended, restated and renamed as the 2014 Long-Term Incentive Plan (the "Plan"). The primary changes effected by the 2014 amendment and restatement were to (a) extend the period during which awards may be granted under the Plan to May 12, 2024, and (b) increase the number of common shares subject to the Plan by 1,100,000 shares. The Plan, as amended, provides for a maximum of 11,900,000 common shares to be granted to eligible employees. At December 31, 2015, approximately 1,385,624 shares remained available for the grant of new awards under the Plan. Specifically, we encourage share ownership by awarding various long-term equity incentive awards under the Plan, consisting of the PSAP and RSAP. We believe that widespread common share ownership by key employees is an important means of encouraging superior performance and employee retention. Additionally, our equity-based compensation programs encourage performance and retention by providing additional incentives for executives to further our growth, development and financial success over a longer time horizon by personally benefiting through the ownership of our common shares and/or rights.

On February 13, 2013, certain executives were awarded rights to receive an aggregate of 79,660 common shares if our calculated return on invested capital ("ROIC"), as defined in the PSAP, is in the top decile of the Bloomberg Comp Group at the end of the three year performance period, which ended on December 31, 2015. This arrangement was recorded as an equity award that required us to recognize compensation expense totaling $9.5 million over the performance period that began on January 1, 2013, of which $3.2 million, $2.9 million and $3.4 million has been recognized in 2015, 2014, and 2013, respectively. At December 31, 2015, the Company had the highest ROIC compared to the Bloomberg Comp Group. The Compensation Committee of our Board of Supervisory Directors verified that the performance target criteria had been met and 73,660 shares vested (6,000 shares were forfeited by participants prior to the end of the performance period). We issued these common shares on December 31, 2015 and, simultaneously, the participants surrendered 25,162 common shares to settle any personal tax liabilities which may result from the award, as permitted by the agreement. We recorded these surrendered shares as treasury stock with an aggregate cost of $2.7 million at $108.74 per share. We have recognized an additional tax liability from the vesting of the PSAP of $0.4 million in 2015.

On February 13, 2014, certain executives were awarded rights to receive an aggregate of 53,548 common shares if our calculated ROIC, as defined in the PSAP, is in the top decile of the Bloomberg Comp Group at the end of the performance period, which ends on the last trading day of 2016, December 30, 2016. Unless there is a change in control as defined in the PSAP, none of these awards will vest if the specified performance target is not met as of the last day of the performance period. This arrangement is recorded as an equity award that requires us to recognize compensation expense totaling $9.0 million over the performance period that began on January 1, 2014, of which $3.0 million and $3.0 million has been recognized in 2015 and 2014, respectively. The unrecognized compensation expense is expected to be recognized over an estimated amortization period of 12 months.

On February 10, 2015, certain executives were awarded rights to receive an aggregate of 106,455 common shares if our calculated ROIC, as defined in the PSAP, is in the top decile of the Bloomberg Comp Group at the end of the performance period, which ends on the last trading day of 2017, December 29, 2017. Unless there is a change in control as defined in the PSAP, none of these awards will vest if the specified performance target is not met as of the last day of the performance period. This arrangement is recorded as an equity award that requires us to recognize compensation expense totaling $11.3 million over the performance period that began on January 1, 2015, of which $3.8 million has been recognized in 2015. The unrecognized compensation expense is expected to be recognized over an estimated amortization period of 24 months.

In 2004, the Compensation Committee of our Board of Supervisory Directors approved the RSAP to attract and retain the best employees, and to better align employee interests with those of our shareholders. Under this arrangement we awarded grants totaling 91,784 shares, 80,983 shares, and 94,620 shares in 2015, 2014, and 2013, respectively. Each of these grants has a vesting period of principally six years and vests ratably on an annual basis. There are no performance accelerators for early vesting for these awards. Awards under the RSAP are classified as equity awards and recorded at the grant-date fair value with the compensation expense recognized over the expected life of the award. As of December 31, 2015, there was $30.0 million of unrecognized total stock-based compensation relating to non-vested RSAP awards. The unrecognized compensation expense is expected to be recognized over an estimated weighted-average amortization period of 45 months. The grant-date fair value of shares granted was $8.9 million, $15.0 million and $12.3 million in 2015, 2014 and 2013, respectively and we have recognized compensation expense of $10.4 million, $10.5 million and $10.3 million in 2015, 2014 and 2013, respectively. The total grant-date fair value, which is the intrinsic value of the shares, vested was $10.4 million, $10.4 million and $9.9 million in 2015,

On May 13, 2014, the 2006 Nonemployee Director Stock Option Plan was amended, restated and renamed as the 2014 Nonemployee Director Stock Incentive Plan (the "Director Plan"). The primary change effected by the 2014 amendment was to extend the period during which awards may be granted under the Director Plan to May 12, 2024. The Director Plan provides common shares for grant to our eligible Supervisory Directors. The maximum number of shares available for award under this plan is 1,400,000 common shares. As of December 31, 2015 approximately 558,139 shares remained available for issuance under the Director Plan. Only non-employee Supervisory Directors are eligible for these equity-based awards under the Director Plan.

In 2011, the Compensation Committee of our Board of Supervisory Directors approved the restricted share award program (the "Program") to compensate our non-employee Supervisory Directors. Under this arrangement we awarded grants totaling 8,616 shares, 4,536 shares and 7,616 shares in 2015, 2014, and 2013, respectively. Each of these grants has a vesting period of 3 years. There are no performance accelerators for early vesting for these awards. Awards under the Program are classified as equity awards and recorded at the grant-date fair value with compensation expense recognized over the expected life of the award. As of December 31, 2015, there was $1.1 million of unrecognized total stock-based compensation relating to non-vested Program awards. The unrecognized compensation expense is expected to be recognized over an estimated weighted-average amortization period of 21 months. The grant-date fair value of shares granted was $0.9 million, $0.9 million and $1.0 million in 2015, 2014, and 2013, respectively, and we have recognized compensation expense of $0.9 million, $0.9 million and $0.7 million in 2015, 2014, and 2013, respectively.

In 2014, we entered into two interest rate swap agreements for a total notional amount of $50 million to hedge changes in the variable rate interest expense on $50 million of our existing or replacement LIBOR-priced debt. Under the first swap agreement of $25 million, we have fixed the LIBOR portion of the interest rate at 1.73% through August 29, 2019, and under the second swap agreement of $25 million, we have fixed the LIBOR portion of the interest rate at 2.50% through August 29, 2024. Each swap is measured at fair value and recorded in our consolidated balance sheet as a liability. They are designated and qualify as cash flow hedging instruments and are highly effective. Unrealized losses are deferred to shareholders' equity as a component of accumulated other comprehensive loss (AOCL) and are recognized in income as an increase to interest expense in the period in which the related cash flows being hedged are recognized in expense.

The Company's only financial assets and liabilities which are measured at fair value on a recurring basis relate to certain aspects of the Company's benefit plans and our derivative instruments. We use the market approach to value certain assets and liabilities at fair value at quoted prices in an active market (Level 1) and certain assets and liabilities using significant other observable inputs (Level 2) with the assistance of a third party specialist. We do not have any assets or liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3). Gains and losses related to the fair value changes in the deferred compensation assets and liabilities are recorded in General and Administrative Expenses in the Consolidated Statement of Operations. Gains and losses related to the fair value of the interest rate swaps are recorded in Other Comprehensive Income. The following table summarizes the fair value balances (in thousands):

We operate in a number of international areas which exposes us to foreign currency exchange rate risk. We do not currently hold or issue forward exchange contracts or other derivative instruments for hedging or speculative purposes (a foreign exchange contract is an agreement to exchange different currencies at a given date and at a specified rate). Foreign exchange gains and losses are the result of fluctuations in the USD against foreign currencies and are included in other (income) expense, net in the Consolidated Statements of Operations. We recognized foreign exchange losses in countries where the USD weakened against the local currency and we had net monetary liabilities denominated in the local currency; as well as countries where the USD strengthened against the local currency and we had net monetary assets denominated in the local currency. We recognized foreign exchange gains in countries where the USD strengthened against the local currency and we had net monetary liabilities denominated in the local currency and in countries where the USD weakened against the local currency and we had net monetary assets denominated in the local currency. Foreign exchange gains and losses are summarized in the following table (in thousands):



	Reservoir Description		Production Enhancement		Reservoir Management		Corporate & Other (1)			Consolidated
December 31, 2015
Revenues from unaffiliated clients	$	473,372	$	267,224	$	56,924	$	—		$	797,520
Inter-segment revenues	8,674		1,837		248		(10,759		)	—
Segment operating income (loss)	111,032		35,027		15,655		(644		)	161,070
Total assets (at end of period)	326,182		210,214		27,076		61,786			625,258
Capital expenditures	17,849		3,292		273		1,383			22,797
Depreciation and amortization	16,778		6,611		1,624		2,444			27,457

December 31, 2014
Revenues from unaffiliated clients	$	518,974	$	467,577	$	98,671	$	—		$	1,085,222
Inter-segment revenue	10,387		2,459		366		(13,212		)	—
Segment operating income (loss)	143,624		165,204		37,220		483			346,531
Total assets (at end of period)	319,325		257,135		34,179		62,686			673,325
Capital expenditures	21,371		7,990		2,681		4,544			36,586
Depreciation and amortization	15,816		7,509		1,393		1,978			26,696




December 31, 2013
Revenue from unaffiliated clients	$	522,251	$	452,415	$	98,842	$	—		$	1,073,508
Inter-segment revenue	3,432		3,140		1,742		(8,314		)	—
Segment operating income (loss)	146,338		154,715		31,555		811			333,419
Total assets (at end of period)	321,106		255,764		37,660		44,834			659,364
Capital expenditures	22,601		7,124		1,366		4,325			35,416
Depreciation and amortization	14,898		7,745		945		1,883			25,471

(1) "Corporate and other" represents those items that are not directly relating to a particular segment and eliminations.

Prior to 2014, we attributed revenue to the country in which the revenue was recorded. During 2014, we began attributing sales revenue to the country where the product was shipped as we feel this gives a clearer view of our operations. We do, however, have significant levels of revenue recorded in the U.S., where the services were performed, that are sourced from projects on non-U.S. oilfields. The following table shows a summary of our U.S. and non-U.S. operations (with 2013 revenue reclassified as described above) for December 31, 2015, 2014 and 2013 (in thousands):



GEOGRAPHIC INFORMATION	United States		Canada		Other Countries (1) (2)		Consolidated
December 31, 2015
Revenue	$	338,907	$	43,808	$	414,805	$	797,520
Property, plant and equipment, net	80,603		12,082		50,526		143,211

December 31, 2014
Revenue	$	515,643	$	105,244	$	464,335	$	1,085,222
Property, plant and equipment, net	83,748		16,057		49,209		149,014

December 31, 2013
Revenue	$	487,252	$	107,842	$	478,414	$	1,073,508
Property, plant and equipment, net	73,870		17,195		47,759		138,824
(1) Revenue earned in other countries, including The Netherlands, was not individually greater than 10% of our consolidated revenue in 2015, 2014 or 2013.
(2) Property, plant and equipment, net in other countries, including The Netherlands, were not individually greater than 10% of our consolidated fixed assets in 2015, 2014 or 2013.



	Quarter ended 2015
	December 31		September 30		June 30		March 31
Services and product sales revenue	$	182,723	$	197,265	$	203,889	$	213,643
Cost of services and product sales	124,709		129,050		134,619		144,274
Other operating expenses	34,372		21,397		21,377		26,652
Operating income	23,642		46,818		47,893		42,717
Interest expense	3,390		3,471		3,116		2,403
Income before income tax expense	20,252		43,347		44,777		40,314
Income tax expense	4,658		9,753		10,075		9,272
Net income	15,594		33,594		34,702		31,042
Net income (loss) attributable to non-controlling interest	176		190		76		(357		)
Net income attributable to Core Laboratories N.V.	$	15,418	$	33,404	$	34,626	$	31,399

Per share information:
Basic earnings per share (1)	$	0.36	$	0.79	$	0.81	$	0.72
Diluted earnings per share (1)	$	0.36	$	0.78	$	0.81	$	0.72

Weighted average common shares outstanding:
Basic	42,355		42,517		42,790		43,340
Diluted	42,518		42,685		42,959		43,466



	Quarter ended 2014
	December 31		September 30		June 30		March 31
Services and product sales revenue	$	278,622	$	276,135	$	267,562	$	262,903
Cost of services and product sales	168,517		166,927		168,158		161,669
Other operating expenses	19,655		20,088		15,270		18,407
Operating income	90,450		89,120		84,134		82,827
Interest expense	2,882		2,561		2,794		2,363
Income before income tax expense	87,568		86,559		81,340		80,464
Income tax expense	20,841		19,909		17,244		19,311
Net income	66,727		66,650		64,096		61,153
Net income attributable to non-controlling interest	537		153		362		89
Net income attributable to Core Laboratories N.V.	$	66,190	$	66,497	$	63,734	$	61,064

Per share information:
Basic earnings per share (1)	$	1.51	$	1.51	$	1.43	$	1.36
Diluted earnings per share (1)	$	1.51	$	1.50	$	1.42	$	1.35

Weighted average common shares outstanding:
Basic	43,742		44,152		44,660		44,908
Diluted	43,927		44,381		44,910		45,182



Exhibit No.	Exhibit Title	Incorporated by Reference from the Following Documents
3.1	Articles of Association of the Company, as amended on May 16, 2012 (including English translation)	Form 10-K, February 19, 2013 (File No. 001-14273)

10.1	Core Laboratories N.V. 2014 Long-Term Incentive Plan (as amended and restated effective as of May 12, 2014)	Proxy Statement dated March 19, 2014 for Annual Meeting of Shareholders (File No. 001-14273)

10.2	Core Laboratories N.V. 2014 Nonemployee Director Stock Incentive Plan (as amended and restated effective as of May 12, 2014)	Proxy Statement dated March 19, 2014 for Annual Meeting of Shareholders (File No. 001-14273)

10.3	Form of Indemnification Agreement to be entered into by the Company and certain of its directors and officers	Form F-1, September 1, 1995 (File No. 000-26710)

10.4	Core Laboratories Supplemental Executive Retirement Plan effective as of January 1, 1998¹	Form 10-K, March 31, 1998 (File No. 000-26710)

10.5	Amendment to Core Laboratories Supplemental Executive Retirement Plan filed January 1, 1998, effective July 29, 1999¹	Form 10-Q, August 16, 1999 (File No. 001-14273)

10.6	Core Laboratories Supplemental Executive Retirement Plan for Monty L. Davis effective January 1, 1999¹	Form 10-Q, August 16, 1999 (File No. 001-14273)

10.7	Amendment to Core Laboratories Supplemental Executive Retirement Plan¹	Form 10-Q, May 15, 2003 (File No. 001-14273)

10.8	Amendment to Core Laboratories Supplemental Executive Retirement Plan dated as of March 5, 2008¹	Form 10-Q, May 12, 2008 (File No. 001-14273)

10.9	Amendment to Core Laboratories Supplemental Executive Retirement Plan for Monty L. Davis dated as of March 5, 2008¹	Form 10-Q, May 12, 2008 (File No. 001-14273)

10.10	Non-Employee Director Compensation Summary	Form 10-K, February 22, 2008 (File No. 001-14273)

10.11	Core Laboratories N.V. 2006 Nonemployee Director Stock Incentive Plan	Proxy Statement dated May 17, 2006 for Annual Meeting of Shareholders (File No. 001-14273)

10.12	Form of Director Performance Share Award Restricted Share Agreement (ROE Based)¹	Form 10-K, February 20, 2007 (File No. 001-14273)

10.13	Form of Restricted Share Award Program Agreement¹	Form 10-K, February 20, 2007 (File No. 001-14273)

10.14	Form of Amendment to Core Laboratories 2008 Non-Employee Director Restricted Performance Share Award Agreement (ROE Based)	Form 10-Q, April 22, 2011 (File No. 001-14273)



10.15	Form of Amendment to Core Laboratories 2009 Non-Employee Director Restricted Performance Share Award Agreement (ROE Based)	Form 10-Q, April 22, 2011 (File No. 001-14273)

10.16	Form of Amendment to Core Laboratories 2010 Non-Employee Director Restricted Performance Share Award Agreement (ROIC Based)	Form 10-Q, April 22, 2011 (File No. 001-14273)

10.17	Form of Core Laboratories 2011 Non-Employee Director Restricted Share Award Program Agreement	Form 10-Q, April 22, 2011 (File No. 001-14273)

10.18	Form of Core Laboratories 2011 Performance Share Award Program Agreement (ROIC Based)	Form 10-Q, April 22, 2011 (File No. 001-14273)

10.19	Form of Core Laboratories 2010 Performance Restricted Share Award Program Agreement (ROIC Based)	Form 10-Q, April 22, 2011 (File No. 001-14273)

10.20	Core Laboratories N.V. Board Succession Plan, dated March 2, 2011	Form 8-K, March 7, 2011 (File No. 001-14273)

10.21	Sixth Amended and Restated Credit Agreement, dated as of August 29, 2014, among Core Laboratories, N.V., and Core Laboratories (U.S.) Interests Holdings, Inc., and the lenders party thereto and Bank of America, N.A., as administrative agent	Form 8-K, August 29, 2014 (File No. 001-14273)

10.22	Amendment No. 1 to the Sixth Amended and Restated Credit Agreement among Core Laboratories N.V. and Core Laboratories (U.S.) Interests Holdings, Inc., as borrowers and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer	Form 8-K, March 16, 2015 (File No. 001-14273)

10.23	Form of Restated Employment Agreement between Core Laboratories N.V. and David M. Demshur dated as of December 31, 2007¹	Form 10-Q, May 12, 2008 (File No. 001-14273)

10.24	Amendment to Restated Employment Agreement dated December 31, 2007, between Core Laboratories N.V. and David M. Demshur¹	Form 10-K, February 22, 2011 (File No. 001-14273)

10.25	Form of Restated Employment Agreement between Core Laboratories N.V. and Richard L. Bergmark dated as of December 31, 2007¹	Form 10-Q, May 12, 2008 (File No. 001-14273)

10.26	Amendment to Restated Employment Agreement dated December 31, 2007, between Core Laboratories N.V. and Richard L. Bergmark¹	Form 10-K, February 22, 2011 (File No. 001-14273)

10.27	Form of Restated Employment Agreement between Core Laboratories N.V. and Monty L. Davis dated as of December 31, 2007¹	Form 10-Q, May 12, 2008 (File No. 001-14273)

10.28	Amendment to Restated Employment Agreement dated December 31, 2007, between Core Laboratories N.V. and Monty L. Davis¹	Form 10-K, February 22, 2011 (File No. 001-14273)

10.29	Master Note Purchase Agreement, dated as of September 30, 2011	Form 8-K, September 30, 2011 (File No. 001-14273)



21.1	Significant Subsidiaries of the Registrant	Filed Herewith

23.1	Consent of PricewaterhouseCoopers LLP	Filed Herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed Herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed Herewith

32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished Herewith

32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Furnished Herewith

101.INS	XBRL Instance Document	Filed Herewith

101.SCH	XBRL Schema Document	Filed Herewith

101.CAL	XBRL Calculation Linkbase Document	Filed Herewith

101.LAB	XBRL Label Linkbase Document	Filed Herewith

101.PRE	XBRL Presentation Linkbase Document	Filed Herewith

101.DEF	XBRL Definition Linkbase Document	Filed Herewith

¹Management contracts or compensatory plans or arrangements.



Name	Legal Seat	Ownership %
Core Laboratories Australia PTY LTD	Perth, Australia	100%
Core Laboratories Canada Ltd.	Alberta, Canada	100%
Core Laboratories International B.V.	Amsterdam, The Netherlands	100%
Core Laboratories LP	Delaware, United States	100%
Core Laboratories Malaysia SDN BHD	Kuala Lumpur, Malaysia	100%
Core Laboratories Sales N.V.	Willemstad, Curacao	100%
Core Laboratories (U.K.) Limited	London, United Kingdom	100%
Owen Oil Tools LP	Delaware, United States	100%
Core Lab de Mexico S.A. de C.V.	Mexico City, Mexico	100%
Saybolt Belgium N.V.	Antwerp, Belgium	100%
Saybolt LP	Delaware, United States	100%
Saybolt Nederland B.V.	Rotterdam, The Netherlands	100%
Saybolt (Singapore) PTE LTD	Singapore, Singapore	100%
Stim-Lab, Inc.	Oklahoma, United States	100%
ZAO Petroleum Analysts	Moscow, Russian Federation	100%



(Mark One)
Q	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2015
	OR

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

	For the transition period from__ ________ ____ ____to _ ____ ____ ____ ____ ___



The Netherlands	Not Applicable
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Strawinskylaan 913
Tower A, Level 9
1077 XX Amsterdam
The Netherlands	Not Applicable
(Address of principal executive offices)	(Zip Code)



Title of each class	Name of each exchange on which registered
Common Shares, EUR 0.02 Par Value Per Share	New York Stock Exchange; Euronext Amsterdam Stock Exchange



Large accelerated filer Q	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)



		Page

PART I
Item 1.	Business	1
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	14
Item 2.	Properties	14
Item 3.	Legal Proceedings	14
Item 4.	Mine Safety Disclosures	14
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
Item 6.	Selected Financial Data	17
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operation	18
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	30
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	32
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	33
Item 11.	Executive Compensation	33
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	33
Item 13.	Certain Relationships and Related Transactions and Director Independence	33
Item 14.	Principal Accountant Fees and Services	33
PART IV
Item 15.	Exhibits, Financial Statement Schedules	34


•	Reservoir Description: Encompasses the characterization of petroleum reservoir rock, fluid and gas samples. We provide analytical and field services to characterize properties of crude oil and petroleum products to the oil and gas industry.


•	Production Enhancement: Includes products and services relating to reservoir well completions, perforations, stimulations and production. We provide integrated services to evaluate the effectiveness of well completions and to develop solutions aimed at increasing the effectiveness of enhanced oil recovery projects.


•	Reservoir Management: Combines and integrates information from reservoir description and production enhancement services to increase production and improve recovery of oil and gas from our clients' reservoirs.



	United States		Europe/Africa/Middle East		Asia Pacific		Canada		Former Soviet Union		Latin/ South America		Consolidated
2015	$	338,907	$	249,679	$	86,001	$	43,808	$	41,450	$	37,675	$	797,520
2014	$	515,643	$	273,452	$	94,328	$	105,244	$	49,778	$	46,777	$	1,085,222
2013	$	487,252	$	263,720	$	113,043	$	107,842	$	49,441	$	52,210	$	1,073,508


▪	market prices of oil and gas and expectations about future prices;


▪	cost of producing and the ability to deliver oil and natural gas;


▪	mergers, consolidations and downsizing among our clients;


▪	the impact of commodity prices on the expenditure levels of our clients;


▪	financial condition of our client base and their ability to fund capital expenditures;


▪	the physical effects of climatic change, including adverse weather, such as increased frequency or severity of storms, droughts and floods, or geologic/geophysical conditions;


▪	level of consumption of oil, gas and petrochemicals by consumers;


▪	cyber-attacks on our network that disrupt operations or result in lost or compromised critical data.


▪	acts of terrorism;


▪	the adoption of legal requirements or taxation, including, for example, a carbon tax, relating to climate change that lower the demand for petroleum-based fuels;


▪	civil unrest or political uncertainty in oil producing or consuming countries;


▪	the business opportunities (or lack thereof) that may be presented to and pursued by us;


▪	availability of services and materials for our clients to grow their capital expenditures;


▪	availability of materials and equipment from key suppliers; and


▪	political actions and requirements of national governments including trade restrictions, embargoes, seizure, detention, nationalization and expropriations of assets;


▪	interpretation of tax statutes and requirements of taxing authorities worldwide, routine examination by taxing authorities and assessment of additional taxes, penalties and/or interest;


▪	international agreements that restrict GHG emissions, such as the agreement reached by almost 200 countries in Paris, France in December 2015 that calls for such countries to set GHG emissions targets in their own countries and to be transparent in how such countries achieve those GHG emissions targets;


▪	fluctuations and changes in currency exchange rates (see section below);


▪	difficulty in repatriating foreign currency received in excess of the local currency requirements; and


▪	current conditions in oil producing countries such as Venezuela, Nigeria, Libya, Iran and Iraq considering their potential impact on the world markets.


▪	difficulties involved in combining disparate company cultures and facilities.



	NYSE				Euronext Amsterdam
	(U.S. Dollars)				(Euros)
2015	High		Low		High		Low
Fourth Quarter	$	125.42	$	$94.36	€	116.00	€	88.50
Third Quarter	$	118.78	$	$91.63	€	107.00	€	87.50
Second Quarter	$	134.87	$	$104.24	€	121.00	€	96.00
First Quarter	$	120.34	$	$87.27	€	104.90	€	77.21
2014
Fourth Quarter	$	147.11	$	$109.88	€	122.00	€	89.66
Third Quarter	$	168.40	$	$143.14	€	125.00	€	109.80
Second Quarter	$	221.00	$	$150.50	€	157.00	€	112.50
First Quarter	$	206.42	$	$172.41	€	145.05	€	130.00



Period	Total Number Of Shares Purchased	Average Price Paid Per Share	Total Number Of Shares Purchased As Part Of A Publicly Announced Program	Maximum Number Of Shares That May Be Purchased Under The Program (4)(5)
October 31, 2015 (1)	62,029	$115.39	62,029	2,445,685
November 30, 2015 (2)	25,325	$120.80	25,325	2,420,847
December 31, 2015 (3)	45,564	$110.71	45,564	2,460,903
Total	132,918	$114.82	132,918


(1)	includes 4,021 shares valued at $0.4 million, or $99.02 per share, surrendered to us by participants in a stock-based compensation plan to settle any personal tax liabilities which may result from the award.


(2)	includes 149 shares valued at $17.3 thousand, or $116.31 per share, surrendered to us by participants in a stock-based compensation plan to settle any personal tax liabilities which may result from the award.


(3)	includes 28,564 shares valued at $3.1 million, or $109.81 per share, surrendered to us by participants in a stock-based compensation plan to settle any personal tax liabilities which may result from the award.


(4)	The maximum number of shares allowed to be purchased under the program was 2,492,279 at September 30, 2015.


(5)	During the quarter 101,542 treasury shares were distributed relating to stock-based awards, including 15,435 in October, 487 in November, and 85,620 in December.


•	Production Enhancement: Includes services and products relating to reservoir well completions, perforations, stimulations and production. We provide integrated services to evaluate the effectiveness of well completions and to develop solutions aimed at increasing the effectiveness of enhanced oil recovery projects.