Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
FORM 10-K
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
 ¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-35471
SAExploration Holdings, Inc.
(Exact name of registrant as specified in its charter) 
Delaware
27-4867100
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
1160 Dairy Ashford Rd., Suite 160, Houston, Texas
77079
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code (281) 258-4400 
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.0001 Par Value
The NASDAQ Capital Market
(Title of each class)
(Name of each exchange on which registered)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨Noþ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes ¨ Noþ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or a emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
Accelerated filer  ¨
Non-accelerated filer  ¨  (Do not check if a smaller reporting company)
Smaller reporting company þ
 
Emerging growth company  ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ Noþ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter was $13,526,290, calculated by reference to the closing price of $3.23 for the registrant’s common stock on The Nasdaq Global Market on that date.
Number of shares of Common Stock, $0.0001 par value, outstanding as of March 9, 2018: 14,907,116
 DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement for 2018 Annual Meeting of Stockholders -- Referenced in Part III of this Report



TABLE OF CONTENTS
 
 
 
 
 
 
 


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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This report contains “forward-looking statements” within the meaning of the federal securities laws, with respect to our financial condition, results of operations, cash flows and business, and our expectations or beliefs concerning future events. These forward-looking statements can generally be identified by phrases such as “expects,” “anticipates,” “believes,” “estimates,” “intends,” “plans to,” “ought,” “could,” “will,” “should,” “likely,” “appears,” “projects,” “forecasts,” “outlook” or other similar words or phrases. There are inherent risks and uncertainties in any forward-looking statements. Although we believe that our expectations are reasonable, we can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Except as required by law, we undertake no obligation to update, amend or clarify any forward-looking statements to reflect events, new information or otherwise. Some of the important factors that could cause actual results to differ materially from our expectations are discussed below. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
Factors that could cause actual results to vary materially from our expectations include the following:
 
the ability to effectively manage our operations during the significant cash flow and liquidity difficulties we are experiencing;
the negative consequences of our restructurings, including the significant dilution of our existing stockholders;
negative events or publicity associated with our restructuring and recapitalization transactions could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition;
developments with respect to the Alaskan oil and natural gas exploration tax credit system that may continue to affect the willingness of third parties to participate in financing and monetization transactions and our ability to timely monetize tax credits that have been assigned to us by our customer;
changes in the Alaska oil and natural gas exploration tax credit system that may significantly affect the level of Alaskan exploration spending;
fluctuations in the levels of exploration and development activity in the oil and gas industry;
intense industry competition;
limited number of customers;
credit and delayed payment risks related to our customers;
the availability of liquidity and capital resources, including our limited ability to make capital expenditures and the potential impact this has on our business and competitiveness;
need to manage rapid growth and contraction of our business;
delays, reductions or cancellations of service contracts;
operational disruptions due to seasonality, weather and other external factors;
crew availability and productivity;
whether we enter into turnkey or term contracts;
high fixed costs of operations;
substantial international business exposing us to currency fluctuations and global factors, including economic, political and military uncertainties;
ability to retain key executives; and
need to comply with diverse and complex laws and regulations.
Refer to the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections of this report for specific risks which would cause actual results to be significantly different from those expressed or implied by any of our forward-looking statements. It is not possible to identify all of the risks, uncertainties and other factors that

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may affect future results. In light of these risks and uncertainties, the forward-looking events and circumstances discussed in this report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. Accordingly, readers of this report are cautioned not to place undue reliance on the forward-looking statements.


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PART I

ITEM 1. Business.

Overview
 
SAExploration Holdings, Inc. and its Subsidiaries (collectively, the “Corporation”, "we", "us", or "our") is an internationally-focused oilfield services company offering a full range of vertically-integrated seismic data acquisition and logistical support services in Alaska, Canada, South America, West Africa and Southeast Asia to our customers in the oil and natural gas industry. In addition to the acquisition of 2D, 3D, time-lapse 4D and multi-component seismic data on land, in transition zones between land and water, and offshore in depths reaching 3,000 meters, we offer a full-suite of logistical support and in-field data processing services. We operate crews around the world that are supported by over 27,500 owned land and marine channels of seismic data acquisition equipment and other leased equipment as needed to complete particular projects. Seismic data is used by our customers, including major integrated oil companies, national oil companies and independent oil and gas exploration and production companies, to identify and analyze drilling prospects and maximize successful drilling. The results of the seismic surveys we conduct belong to our customers and are proprietary in nature; we do not acquire data for our own account or for future sale or maintain multi-client data libraries.

We specialize in the acquisition of seismic data in logistically complex and challenging environments and delicate ecosystems, including jungle, mountain, arctic and subaquatic terrains. We have extensive experience in deploying personnel and equipment in remote locations, while maintaining a strong quality, health, safety and environmental ("QHSE") track record and building positive community relations in the locations where we operate. We employ highly specialized crews made up of personnel with the training and skills required to prepare for and execute each project and, over time, train and employ large numbers of people from the local communities where we conduct our surveys. Our personnel are equipped with the technology necessary to meet the specific needs of the particular project and to manage the challenges presented by sensitive environments.
We were initially incorporated in Delaware on February 2, 2011, under the name Trio Merger Corp. as a blank check company in order to serve as a vehicle for the acquisition of a target business. On June 24, 2013, we completed a business combination in which the entity formerly known as SAExploration Holdings, Inc. (“Former SAE”) merged into our wholly-owned subsidiary (the “Merger”), and we operate the business of Former SAE.

Our principal headquarters are located in Houston, Texas at 1160 Dairy Ashford Rd., Suite 160, Houston, Texas, 77079, Telephone: (281) 258-4400, and our web address is www.saexploration.com. We do not intend for information contained in our website to be a part of this report.
Our operations in our various geographic locations are conducted through our subsidiary SAExploration, Inc. and its wholly-owned subsidiaries and branch offices in the United States (primarily Alaska), Canada, Peru, Colombia, Bolivia, and Malaysia.

Recent Developments
On December 19, 2017, we entered into a restructuring support agreement (the “2017 Restructuring Support Agreement”) with holders (the “2017 Supporting Holders”) that beneficially owned in excess of 85% in principal amount of our 10.000% Senior Secured Second Lien Notes due 2019 (the “Second Lien Notes”), pursuant to which the 2017 Supporting Holders agreed to enter into and implement a deleveraging restructuring transaction (the “2017 Restructuring”), subject to the terms and conditions of the 2017 Restructuring Support Agreement with us. The closing of the 2017 Restructuring occurred on January 29, 2018 and has significantly restructured our debt and changed our capital structure. The 2017 Restructuring, as well as our 2016 Restructuring (collectively the "Restructurings") are discussed further in Note 2 to our Consolidated Financial Statements.

Seismic Data Acquisition Services
 
We provide a full range of seismic data acquisition services, including in-field data processing, and related logistics services. We currently provide our services on a proprietary basis to our customers and the seismic data acquired is owned by our customers once acquired.
Our seismic data acquisition and logistics services include the following:
Program Design
Planning and Permitting

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Camp Services
Survey
Drilling
Recording
Reclamation; and
In-field Data Processing
Program Design, Planning and Permitting. A seismic survey is initiated at the time the customer requests a proposal to acquire seismic data on its behalf. We employ an experienced design team, including geophysicists with extensive experience in 2D, 3D, time-lapse 4D, and multi-component survey design, to recommend acquisition parameters and technologies to best meet the customer’s exploration objectives. Our design team analyzes the request and works with the customer to put an operational, personnel and capital resource plan in place to execute the project.
Once a seismic program is designed, we assist the customer in obtaining the necessary permits from governmental authorities and access rights of way from surface and mineral estate owners or lessees where the survey is to be conducted. It is usually our permitting crew that is first to engage with the local residents and authorities. We believe our knowledge of the local environment, cultural norms and excellent QHSE track record enable us to engender trust and goodwill with the local communities, which our customers are able to leverage over the longer exploration cycle in the area.
Camp Services. We have developed efficient processes for assembling, operating and disassembling field camps in challenging and remote project locations. We operate our camps to ensure the safety, comfort and productivity of the team working on each project and to minimize our environmental impact through the use of wastewater treatment, trash management, water purification, generators with full noise isolation and recycling areas.
In areas like South America and Southeast Asia, logistical support needs to be in place to establish supply lines for remote jungle camps. To insure the quality of services delivered to these remote camps, we own ten supply and personnel river vessels to gain access to remote jungle areas. We also have five jungle camps and a series of 40 fly camps that act as advance camps from the main project camp. Each of these jungle base camps contains a full service medical facility complete with doctors and nurses in the remote chance any potential injuries need to be stabilized for medical transport. The camps are equipped with full meal kitchens held to high standards of cleanliness, sleeping and recreational quarters, power supply, communications links, air support, water purification systems, black water purification systems, offices, repair garages, fuel storage and many more support services.
Survey and Drilling. In a typical seismic recording program, the first two stages of the program are survey and drilling. Once the permitting is completed, our survey crews enter the project areas and begin establishing the source and receiver placements in accordance with the survey design agreed to by the customer. The survey crew lays out the line locations to be recorded and, if explosives are being used, identifies the sites for shot-hole placement. The drilling crew creates the holes for the explosive charges that produce the necessary acoustical impulse.
The surveying and drilling crews are usually employed by us but may be third party contractors depending on the nature of the project and its location. Generally, the choice of whether to subcontract out services depends on the expertise available in a certain region and whether that expertise is more efficiently obtained through subcontractors or by using our own labor force. For the most part, services are subcontracted within Alaska and Canada and our personnel are used in other regions where we operate. When subcontractors are used, we manage them and require that they comply with our work policies and QHSE objectives.
In Alaska and Canada, the surveying and drilling crews are typically provided by third party contractors but are supervised by our personnel. In Alaska and Canada, our vibroseis source units consist of the latest source technology, including eight AHV IV 364 Commander Vibrators and twelve environmentally friendly IVI mini vibrators, complete with the latest Pelton DR electronics. In South America and Southeast Asia, we perform our own surveying and drilling, which is supported by up to 200 drilling units, including people-portable, low impact self-propelled walk behind, track-driven and heli-portable deployed drilling rigs. Our senior drilling staff has a combined work experience of over 50 years in some of the most challenging environments in the world. On most programs there are multiple survey and drilling crews that work at a coordinated pace to remain ahead of the data recording crews.
Recording. We use equipment capable of collecting 2D, 3D, time-lapse 4D and multi-component seismic data. We utilize vibrator energy sources or explosives depending on the nature of the program and measure the reflected signals with strategically placed

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sensors. Onshore, geophones are manually buried, or partially buried, to ensure good coupling with the surface and to reduce wind noise. Offshore, the reflected signals are recorded by either hydrophones towed behind a survey vessel or by geophones placed directly on the seabed. We increasingly employ ocean bottom nodes positioned by remote operated vehicles on the seafloor in our marine data acquisition operations. We have available over 27,500 owned land and marine seismic recording channels with the ability to access additional equipment, as needed, through rental or long-term leasing sources. All of our systems record equivalent seismic information but vary in the manner by which seismic data is transferred to the central recording unit, as well as their operational flexibility and channel count expandability. We utilize 11,500 channels of Sercel 428/408 equipment, 6,000 channels of Fairfield Land Nodal equipment and 10,000 channels of Geospace GSX equipment.
Historically, we have made significant capital investments to increase the recording capacity of our crews by increasing channel count and the number of energy source units we operate. This increase in channel count demand is driven by customer needs and is necessary in order to produce higher resolution images, increase crew efficiencies and undertake larger scale projects. In response to project-based channel requirements, we routinely deploy a variable number of channels with a variable number of crews in an effort to maximize asset utilization and meet customer needs. When recording equipment is at or near full utilization, we utilize rental equipment from strategic suppliers to augment our existing inventories. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and increased margins.
Historically, we have dedicated a significant portion of our capital investment to purchasing and leasing wireless recording systems rather than the traditional wired systems. We utilize this equipment as primarily stand-alone recording systems, but on occasion it is used in conjunction with cable-based systems. The wireless recording systems allow us to gain further efficiencies in data recording and provide greater flexibility in the complex environments in which we operate. In addition, we have realized increased crew efficiencies and lessened the environmental impact of our seismic programs due to the wireless recording systems because they require the presence of fewer personnel and less equipment in the field. We believe we will experience continued demand for wireless recording systems in the future.
We also utilize multi-component recording equipment on certain projects to further enhance the quality of data acquired and help our customers enhance their development of producing reservoirs. Multi-component recording involves the collection of different seismic waves, including shear waves, which aids in reservoir analysis such as fracture orientation and intensity in shales and allows for more descriptive rock properties.
Reclamation. We have experienced teams responsible for reclamation of the areas where work has been performed so as to minimize the environmental footprint from the seismic program. These programs can include reforestation or other activities to restore the natural landscape at our worksites.
In-field Data Processing. Our knowledgeable and experienced team provides our customers with superior quality in-field data processing. We believe that our strict quality control processes meet or surpass industry-established standards, including identifying and analyzing ambient noise, evaluating field parameters and employing obstacle-recovery strategies. Using the latest technology, our technical and field teams electronically manage customer data from the field to the processing office, minimizing time between field production and processing. All of the steps employed in our in-field data processing sequence are tailored to the particular customer project and objectives.

Industry Overview

Seismic technology is the primary tool used to locate oil and gas reserves, and it facilitates the development of complex reservoirs. Seismic data is used to pinpoint and determine the locations of subsurface features favorable for the accumulation of hydrocarbons, as well as define the make-up of the sedimentary rock layers and their corresponding fluids. Seismic data is acquired by introducing acoustic energy into the earth and water through controlled energy sources. Seismic energy sources can consist of truck-mounted vibration equipment in accessible terrain, explosives such as dynamite in more difficult terrain, or vessel-mounted air guns in shallow water and certain marsh environments. The sound waves created by explosives or vibration equipment are reflected back to the surface and collected by seismic sensors referred to as “geophones” or “hydrophones,” which measure ground and water displacement. One or more strategically positioned seismic sensors are connected to a recording channel which transmits the data to a central recording location. A typical project involves the use of thousands, and sometimes tens of thousands, of channels recording simultaneously over the survey area. In general, the higher the number of recording channels employed in a given survey, the richer the data set that is produced.

A seismic survey is acquired with a surface geometry grid of seismic energy sources and receivers extending over very large areas. The size of this grid varies with and depends on the size, depth and geophysical characteristics of the target to be imaged. The lines must be accurately positioned, so the location of each source and receiver point is obtained using either GPS, inertial, or

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conventional optical survey methods depending upon the vegetation and environment in the prospect area. Seismic receivers are deployed on the surface of the area being surveyed at regular intervals and patterns to measure, digitize and transmit reflected seismic energy to a set of specialized recording instruments. The transportation of cables, geophones and field recording equipment can be by truck, vessel or helicopter depending upon the terrain and environment within the area to be imaged.
Land seismic data acquisition. For land applications, geophones are buried, or partially buried, to ensure good coupling with the surface and to reduce wind noise. Burying geophones in the ground is a manual process and may involve anywhere from a few to more than 100 people depending on the size of the seismic crew and the terrain involved. Cables that connect the geophones to cabled recording systems may also be deployed manually or, in some cases, automatically from a vehicle depending on the terrain. The acoustic source for land seismic data acquisition is typically a fleet of large hydraulic vibrator trucks, but may also be explosives detonated in holes drilled for such purposes.
On a typical land seismic survey, the seismic recording crew is supported by a permitting and surveying crew along with a vibroseis and/or drilling crew. The permitting crew secures permission from the landowner and mineral owner or lessee to gain access to the surface and subsurface rights to conduct the seismic program. The surveying crew lays out the receiver locations to be recorded and, in a survey using an explosive source, identifies the sites where the drilling crew creates the holes for the explosive charges that produce an acoustical impulse. In other surveys, a mechanical vibrating unit, such as a vibrator truck, is used as the seismic energy source. The seismic crew lays out the geophones and recording instruments, directs shooting operations and records the acoustical signal reflected from subsurface strata. The number of individuals on each crew is dependent upon the size and nature of the seismic survey.
Offshore seismic data acquisition. In marine surveys, air guns, which release high-pressure compressed air into the water column, are used as the acoustic energy source. For ocean bottom cable operations, an assembly of vertically oriented geophones and hydrophones connected by electrical wires typically is deployed on the sea floor to record and relay data to a seismic recording vessel. Increasingly, ocean bottom nodes positioned by remote operated vehicles are used in areas of obstructions (such as production platforms) or shallow water inaccessible to ships towing seismic streamers (such as submerged cables).
Transition zone seismic data acquisition. In the transition zone area where land and water come together, elements of both land data acquisition and offshore data acquisition are employed. Transition zone seismic data acquisition is similar to ocean bottom cable applications in that both hydrophones and geophones are lowered to the ocean floor. However, due to the shallow water depths, only small vessels and manual labor can be used to deploy and retrieve the cables. Additionally, the source vessels and acoustic source arrays must be configured to run in shallow water. In transition zone areas consisting of swamps and marshes, explosives must be used as an acoustic source in addition to air guns.
Two-dimensional, or 2D, seismic data is recorded using single lines of receivers crossing the earth’s surface, and, once processed, results in only a profile image of the earth, and the data is generally used only to identify gross structural features. Prior to 1980, all seismic data acquired was 2D, and 2D surveys are still widely employed in locations previously unexplored by E&P companies to provide preliminary data for broad-scale exploration evaluation. Three-dimensional, or 3D, seismic data surveys have proven more effective in providing detailed views of subsurface structures.
The increased use of 3D seismic data by the oil and natural gas industry in the 1980s helped drive significant increases in drilling success rates as better data quality allowed operators to optimize well locations and results. Today, the vast majority of seismic data acquired in North America is 3D, of which high density 3D is a growing component.
More recently, the seismic industry has seen the development of four-dimensional, or 4D, imaging technology, also known as time-lapse seismic. 4D seismic data incorporates numerous 3D seismic surveys over the same reservoir at specified intervals of time and can help determine changes in flow, pressure and saturation. As hydrocarbons are depleted from a field, the pressure and composition of the fluids may change. By scanning a reservoir over a given period of time, the flow of the hydrocarbons within can be traced and better understood. In addition, 4D seismic data can help geologists understand how a reservoir reacts to gas injection or water flooding and can help locate untapped pockets of oil or natural gas within the reservoir.
In conventional 3D seismic surveys, only the primary wave, or P-wave, is acquired. P-wave reflection cannot always image fluid saturated zones properly. Multi-component seismic data acquisition captures the seismic wave field more completely than conventional P-wave techniques. In multi-component acquisition, multiple sets of data are received at each receiver, P-wave and two measurements (X, Y) of the shear wave, or S-wave. Information obtained from the S-wave passing through a fluid-saturated medium provides a better interpretation of the reservoir structure. Evaluating P- and S-wave data together provides additional information to reduce uncertainty in prospect evaluation.

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Once seismic data is acquired, complex mathematical algorithms are used to transform the data into 2D profiles, 3D volumes of the earth’s subsurface or 4D time-lapse seismic data. These images are then interpreted by geophysicists and geologists for use by oil and natural gas companies in evaluating prospective areas, designing drilling programs, selecting drilling sites and managing producing reservoirs.
Markets and Trends

North America

While the last several years have seen a decline in demand, the North American market has historically been a stable and sustainable market for 3D seismic data acquisition. Use of 3D technology is the norm in the United States and Canada as international oil companies seek to maximize the efficiency of their reservoirs and reduce exploration risk.
We expanded into North America in 2011 through our acquisitions of Datum Exploration Ltd. in Canada and Northern Exploration Services in Alaska. With each of those acquisitions, we brought on board personnel with extensive operations experience in each location. Our operations in the North American market are consistent with our strategy to help increase our equipment utilization rates, while concurrently increasing margins, by balancing growth in North and South America, which have complementary operating seasons. While this model continues to be a viable operating model, the industry downturn has created significant pressure on competitive cost structures and pricing, particularly during the early 2017 winter season. However, we are beginning to see characteristics that would suggest this trend may be shifting towards an increase in overall regional activity assuming there is a longer period of consistency in the commodity price environment.
South America
The economies in South American countries continue to expand and develop, demanding significantly more energy to fuel their growth. As the political environments stabilize, oil companies are increasing operations in the market and are seeking experienced seismic service providers with complex environment know-how, strong QHSE records and excellent relations with local communities to satisfy their exploration needs.
We have maintained operations in South America since 2006 while further growing our presence in Bolivia, Brazil, Colombia, and Peru. However, the global oil and natural gas industry downturn significantly impacted exploration activity in South America particularly during 2017 and 2016. While some improvements in the level of customer interest can be seen by an increase in inquiries and subsequent tenders, no assurance can be given that this will result in increased activity or that future decreases in activity will not occur again.
Southeast Asia
Exploration activities in Southeast Asia have declined recently with lower commodity prices but there is a steady demand for energy in the region. In 2010, we entered the Southeast Asian market by commencing operations in Papua New Guinea for one of our major long-time customers. We have expanded our operations in Southeast Asia into New Zealand and deep-water marine work in Malaysia. We expect Southeast Asia to continue to be a predominantly marine-based market in the current commodity price environment. This trend is expected to continue as long as customers remain hesitant to commit capital to large onshore projects that are more exploration driven.
West Africa
In late 2016, we entered the West Africa market to perform a deep-water ocean bottom marine project for a major customer. Historically, West Africa has presented numerous offshore marine opportunities. More recently, offshore marine seismic activity has been increasing in certain West African countries. These projects are more focused on production-enhancement initiatives than new exploration. Despite the current macro-economic instability related to the oil and natural gas industry downturn, we expect overall offshore marine seismic activity to continue to improve in the near to medium-term future.
Strengths

Full service logistics provider. A majority of our revenues is earned through high-margin logistics-related activities performed in-house. Unlike many other seismic data acquisition companies, we focus on providing a complete service and logistical solutions package, especially in our international operations, which allows efficient movement into remote areas. This provides us with opportunities to capture a larger portion of the revenues associated with each project and gives us what we believe to be a strategic advantage over our competitors, who generally outsource logistics services to multiple third parties. Usually we are the first point of contact with the local communities, and we believe having contact with these communities from initiation of the project through the seismic phase and demonstrating our commitment to QHSE forms relationships that benefit us and our customers over the

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longer term. Additionally, our logistical expertise can be a value proposition in price negotiations with our customers, allowing us to maintain higher margins in certain regions of the world, particularly in the more remote areas and challenging environments.
International platform. We operate in numerous regions around the world and continue to maintain our market share in those markets. Our experience includes projects in Alaska, Canada, Bolivia, Brazil, Colombia, Peru, Malaysia, Papua New Guinea, West Africa and New Zealand. We maintain a local presence in many of these areas. As the majority of our operations are focused in locations previously unexplored by E&P companies, the first projects in those areas tend to be for the acquisition of 2D data for preliminary, broad-scale exploration evaluation. That initial acquisition often leads to further work, as the 2D data is used to determine the location and design of additional 3D and 4D surveys, which are then used for more detailed analysis to maximize actual drilling potential and success. Typically, once we are hired for a project, we tend to get follow-on surveys due to our familiarity with the customer, the local communities and the project. The international platform also enables us to expand and contract in various regions around the world to match the changes in demand in certain regions as driven by commodity prices, economic factors and energy consumption in the local markets.
Extensive experience in challenging environments. We specialize in seismic data acquisition services in logistically challenging environments on land, in transition zones and in water. We believe that our extensive experience operating in such complex locations, including our expertise in logistics management and deploying personnel and equipment customized for the applicable environment, provides us with a significant competitive advantage. Many of the areas of the world where we work have limited seasons for seismic data acquisition, requiring high utilization of key personnel and redeployment of equipment from one part of the world to another. Most of our remote area camps, drills and support equipment are easily containerized for transport to locations anywhere in the world. As a result, if conditions deteriorate in a current location or demand rises in another location, we are able to quickly redeploy our crews and equipment to other parts of the world. We have a logistical support department that works with management to keep our equipment strategically located in areas of high utilization.
Strong local relationships and stringent QHSE processes. E&P companies seek experienced seismic service providers with complex environment know-how, strong QHSE records and excellent relations with local communities to satisfy their seismic needs. Our highly trained and qualified QHSE team has extensive experience working in diverse ecosystems and complex cultural environments. We believe this experience allows us to deliver high quality data and efficient operations through systems and processes designed to minimize health and safety risk and overall community and environmental impact. We believe that our strong local relationships, QHSE track record and our history of successful reclamation programs facilitate negotiating permits and other seismic data acquisition rights on behalf of our customers.
Cash flow generation supported by backlog and competitive bids. As of December 31, 2017, we had approximately $50 million of backlog under contract, in addition to approximately $478 million of bids outstanding. We believe our backlog results in comparatively better visibility to future cash flows relative to our peers. Such visibility is also evidenced by our number of bids outstanding. Our key operations outside of North America are generally in countries with strict concession leasing requirements, resulting in clients planning seismic shoots well in advance of the capital being spent. Additionally, the short duration of operating seasons, especially in Alaska, leads to more advanced planning which in turn results in a more accurate cash flow forecast. Non-North American seismic shoots are also less susceptible to cancellation due to the long-term nature of very expensive development programs compared to more volatile, commodity-price driven shorter-term projects typical of North America.

Strong relationships with blue chip customer base. Members of our management team have long-standing relationships often extending over 30 years with many of the largest oil and gas companies in the world. Our global operating footprint allows us to leverage those relationships throughout the world, and we believe our prior performance for those customers enhances our ability to obtain new business from existing and past customers.
Experienced management team with significant operational experience and ownership stake. We believe the experience, knowledge base and relationships that our management team has built over the years enhance our operating and marketing capabilities and underlie our strong reputation in the industry. In fact, we believe the operating expertise of our management team frequently leads to winning bids for new business. Virtually every member of our management team has technological and first-hand experience of the seismic data acquisition industry stemming from years of field work.

Strategy
 
We believe we have a strategic advantage over a substantial number of our competitors in the areas in which we operate because of our expertise in logistics and our ability to provide a complete solution in remote and complex areas.
We plan to build upon our competitive strengths to grow our business through the following strategies:

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Maintain strict focus on contract work with key clients. We intend to continue to work on a fully contracted basis with major national and international oil and gas companies and capitalize on our long-term relationships with our customers. Unlike many of our competitors, we do not acquire data for our own use or maintain multi-client data libraries, which are either unfunded or partially funded speculative libraries, and involve significantly more risk and uncertainty. We seek to add value for our customers through a material reduction of the following risks:

Exploration risk-we deliver consistent high-quality seismic data utilizing the most advanced technology;

Data acquisition risk-we fulfill our promises regarding the timing, quality and scope of our services;

Reputation risk-we attract and retain highly skilled and experienced professionals who embody our strong focus on customer service, safety and environmental safeguards;

QHSE risk-we place the highest priority on the health and safety of our workforce, the protection of our assets, the environment and the communities where we conduct our work, and we strive for continual improvement in all QHSE aspects; and

Financial risk-we are able to employ a higher proportion of turnkey contracts in our operations, which shift most of the business interruption risks onto us.

Provide full in-house logistics services. We intend to continue to focus on our logistics expertise, which, in addition to our seismic data acquisition abilities, allows us to provide a complete service package to our customers. We believe our vertical integration will continue to provide for efficient movement into remote areas as we further expand internationally, giving us a strategic advantage over our competitors. Many of the areas of the world where we work have limited seasons for seismic data acquisition, requiring high utilization of key personnel and redeployment of equipment from one part of the world to another. We believe that few of our competitors have a global reach that is similar to ours.

Focus on global diversification and capitalize on market positioning in emerging basins. We seek to maintain our market share in the markets in which we currently operate and continue our positioning into other emerging markets, such as worldwide ocean bottom seismic services, which we believe hold the highest degree of potential for opportunities during this downturn in the overall market. Emerging economies will likely continue to expand and develop, demanding significantly more energy to fuel their growth. As the political environments stabilize in many of those countries, oil and natural gas companies will likely increase operations in these markets. With our geographic expansion from providing services exclusively in South America to providing services in Alaska, Canada, Southeast Asia and West Africa, we are able to achieve better utilization of our personnel and equipment through redeployment from off-season areas to in-season areas, helping to reduce some of the volatility in our financial performance.

Maintain local relationships and stringent QHSE processes as the foundation of all our projects. We plan to maintain our focus on strong community relations and QHSE standards. We believe our continued success in those areas can be leveraged to help us further maintain our market share in these emerging markets.
 
Continue higher utilization of turnkey contracts to capitalize on higher operating margins. Our contracts for proprietary seismic data acquisition services reflect a high proportion of turnkey contracts, which are fixed fee, compared to term contracts, which use a variable or day-rate fee basis. This provides us with the opportunity to maximize the advantage we have from being a full-service provider and the operational efficiencies created by our vertical integration. Our customers prefer turnkey contracts because they shift much of the business interruption risk onto us. We also increasingly use hybrid contracts where we may share with our customers a certain degree of the risks for certain business interruptions, such as weather, community relations and permitting delays, that are outside of our control.

We enable these strategies by continuing to pursue excellence in the following activities:
Building and maintaining mutually beneficial, long-term relationships with customers;
Aggressively marketing our capabilities and customer-value added proposition;
Continually monitoring technological developments in the industry and, as needed, implementing cutting-edge technologies that can give us a competitive advantage;
Sharing best practices across regions to ensure the consistent delivery of high quality service; and

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Continuing to seek innovative ideas to reduce the seasonal gaps in our equipment utilization rates.

Seasonal Variation in Business
Seismic data acquisition services are performed outdoors and, consequently, are subject to weather and seasonality. Particularly in Alaska and Canada, the primary season for seismic data acquisition is during the winter, from approximately December to April, since much of the terrain for seismic data acquisition cannot be accessed until the ground has frozen. The weather conditions during this time of year can affect the timing and efficiency of operations. In addition, this prime season can be shortened by warmer weather conditions.
In South America and Southeast Asia, our operations are affected by the periods of heavy rain in the areas where seismic operations are conducted. Specifically, the jungle areas of Colombia, Bolivia and Peru are affected by heavy rain during certain parts of the year so we must either avoid taking projects during these time periods or limit the weather risk in a particular customer contract. Many of the heavy rain periods in South America, though, are during the high season for Alaska and Canada, and there are opportunities to maximize the utilization of equipment and personnel by moving them between these regions to take advantage of the different high seasons.
In all areas of operation, the weather is an uncontrollable factor that affects our operations at various times of the year. We try to minimize these risks during the bidding process by utilizing the expertise of our personnel as to the weather in a particular area and through the negotiation of downtime clauses in our contracts with our customers. Due to the unpredictability of weather conditions, there may be times when adverse conditions substantially affect our operations and the financial results of a particular project may be impacted.

Marketing
 
Our services are marketed from our various offices around the world. We have a corporate business development and marketing staff and also have local managers who interact with customers in each country of operations. Through these customer interactions, we are able to remain updated on a customer’s upcoming projects in the area and to work with the customer on projects in other countries.
Contracts are obtained either by direct negotiation with a prospective customer or through competitive bidding in response to invitations to bid. Most of our revenue historically has been generated through repeat customer sales and new sales to customers referred by existing and past customers. In addition, a significant portion of our engagements results from competitive bidding. Contracts are awarded primarily on the basis of price, experience, availability, technological expertise and reputation for dependability and safety. With the involvement and review of senior management, bids are prepared by knowledgeable regional operations managers who understand their respective markets, customers and operating conditions and who communicate directly with existing and target customers during the bid preparation process.
We also work closely with customers on a direct award basis to plan particular seismic data acquisition projects. Due to the complexity of the areas where we do business, these projects can take a number of months in planning and consulting with the customer on exploration goals and parameters of the projects to fit within a particular budget. By working closely with the customer, we are able to acquire seismic data for a project efficiently and within the customer’s required timeframe.
Contracts and Backlog

We conduct data acquisition services under master service agreements with our customers that set forth certain obligations of our customers and us. A supplemental agreement setting forth the terms of a specific project, which may be canceled by either party on short notice, is entered into for every data acquisition project. The supplemental agreements are either “turnkey” agreements that provide for a fixed fee to be paid to us for each unit of data acquired, or “term” agreements that provide for a fixed hourly, daily or monthly fee during the term of the project. Turnkey agreements generally mean more profit potential, but involve more risks due to potential crew downtimes or operational delays. Under term agreements, we are ensured a more consistent revenue stream with improved protection from crew downtime or operational delays, but with a decreased profit potential.
Our contracts for proprietary seismic data acquisition services reflect a high proportion of turnkey contracts, which is preferred by our customers because it shifts much of the business interruption risk onto us; however, it provides us with the greatest opportunity to maximize the advantage we have from being a full-service provider and the operational efficiencies created by our vertical

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integration. We attempt to negotiate on a project-by-project basis some level of weather downtime protection within the turnkey agreements and increasingly use hybrid contracts where we may share with our customers a certain degree of the risks for certain business interruptions, such as weather, community relations and permitting delays, that are outside of our control.
Our backlog estimates represent those projects for which a customer has executed a contract or signed a binding letter of award. Our backlog can vary significantly from time to time, particularly if the backlog is made up of multi-year contracts with some of our more significant customers. Backlog estimates are based on a number of assumptions and estimates including assumptions related to foreign exchange rates and proportionate performance of contracts. The realization of our backlog estimates is further affected by our performance under term rate contracts, as the early or late completion of a project under term rate contracts will generally result in decreased or increased, as the case may be, revenues derived from those projects. Contracts for services are also occasionally modified by mutual consent and often can be terminated for convenience by the customer. Because of potential changes in the scope or schedule of our customers’ projects, and the possibility of early termination of customer contracts, we cannot predict with certainty when or if our backlog will be realized. Material delays, payment defaults or cancellations on the underlying contracts could reduce the amount of backlog currently reported and, consequently, could inhibit the conversion of that backlog into revenues. In addition, worsening overall market conditions are likely to result in further reductions of backlog, which will impact our financial performance.

Customers
 
Our customers include national and international oil companies and independent oil and gas exploration and production companies. Our revenues are derived from a concentrated customer base; however, we are not substantially dependent on any one customer. Based on the nature of our contracts and customer projects, our significant customers can and typically do change from year to year and the largest customers in any one year may not be indicative of the largest customers in the future. During the year ended December 31, 2017, we had three customers, Conoco Phillips Alaska, Inc., Chevron and Hocol Petroleum Limited, that individually exceeded 10% of our consolidated revenue and represented 75% of consolidated revenue for the year. During the year ended December 31, 2016, we had three customers, Alaskan Seismic Ventures, BG Bolivia Corporation and Hocol Petroleum Limited, that individually exceeded 10% of our consolidated revenue and represented 74% of our consolidated revenue for the year.

Competition
 
The acquisition of seismic data for the oil and gas industry is a highly competitive business. Factors such as price, experience, asset availability and capacity, technological expertise and reputation for dependability and safety of a crew significantly affect a potential customer’s decision to award a contract to us or one of our competitors. In addition, the recent excess supply and downturn in commodity prices has decreased demand for seismic services, further intensifying the competitive landscape and causing further pressure on pricing and margins.
Our competitors include much larger companies with greater financial resources, more available equipment and more crews, as well as companies of comparable and smaller sizes. Our primary competitors are Compagnie Générale de Géophysique (CGG), Geokinetics, Inc., Global Geophysical Services, Inc., BGP, Inc. and Dawson Geophysical Company. In addition to those companies, we also compete for projects from time to time with smaller seismic companies that operate in local markets.
Intellectual Property
 
We rely on certain proprietary information, proprietary software, trade secrets and confidentiality and licensing agreements to conduct our operations. We continually strive to improve our operating techniques and technologies, through internal development activities and working with vendors to develop new processes and technologies to maintain pace with industry innovation. Through this process, we have developed certain proprietary processes and methods of doing business, particularly with respect to logistics. Although those processes and methods may not be patentable, we seek to protect our proprietary information by entering into confidentiality agreements with our key managers and customers.
Equipment Purchases and Capital Expenditures
 
During 2017, we made minimal capital expenditures of approximately $2.7 million, primarily related to the purchase of a set of vibrators and additional camp equipment. During 2016, we made capital expenditures of approximately $3.4 million for the purchase of vibrators for our North American operations. Under our current business model, capital expenditures will be kept at minimum levels, other than very low maintenance expenditures, until we see improvement in the overall oil and natural gas market.


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Historically, in line with our focus on wireless land data acquisition, we purchased a cable-less seismic data acquisition system which allows up to three crews to operate under the system at the same time. Following customer needs for higher density land programs using a single point receiver application and to answer the demand for conventional and unconventional oil and gas exploration, we purchased high sensitivity geophones and two types of vibrators, further strengthening our position as a full solution provider for land data acquisition methods and technologies. Additional equipment investments were made for ongoing operations in Alaska in order to increase efficiency. We also invested in cable equipment in order to provide customers in Latin America with cable systems as wireless technology is slower to take hold in that market.
We will continue to employ and expand as needed our wireless equipment on a worldwide basis while maintaining the ability to provide services to the still existing cable markets. Our capital purchases have and will allow us to take advantage of all aspects of the geophysical exploration services market, ranging from land, marine and transition zone data acquisition; 2D, 3D, 4D and multi-component data acquisition; use of different methods to acquire data such as using vibroseis (vibrating) and impulsive sources; as well as vertical seismic profiling and reservoir monitoring. Investments in expanding further into our South America and Southeast Asia markets will also focus upon surveying, drilling and base camp operations.

Government and Environmental Regulations
 
Our operations are subject to various international, federal, provincial, state and local laws and regulations. Those laws and regulations govern various aspects of operations, including the discharge of explosive materials into the environment, requiring the removal and clean-up of materials that may harm the environment or otherwise relating to the protection of the environment and access to private and governmental land to conduct seismic surveys. We believe we have conducted our operations in material compliance with applicable laws and regulations governing our activities.
The costs of acquiring permits and remaining in compliance with environmental laws and regulations, title research, environmental studies and surveys are generally borne by our customers. Although our direct costs of complying with applicable laws and regulations have historically not been material, the changing nature of such laws and regulations makes it impossible to predict the cost or impact of such laws and regulations on future operations. Additional United States or foreign government laws or regulations would likely increase the compliance and insurance costs associated with our customers’ operations. Significant increases in compliance expenses for customers could have a material adverse effect on customers’ operating results and cash flows, which could also negatively impact the demand for our services.
Employees and Subcontractors
 
As of February 28, 2018, we had 1,237 employees, 88 of whom were located in the United States. From time to time and on an as-needed basis, we supplement our regular workforce with individuals that we hire temporarily or as independent contractors in order to meet certain business needs. Our U.S. employees are not represented by any collective bargaining agreement, and we believe that our employee relations are good.
Generally, the choice of whether to subcontract out services depends on the expertise available in a certain region and whether that expertise is more efficiently hired through subcontractors or by using our own labor force. For the most part, services are subcontracted within North America and our personnel are used in other regions where we operate. When subcontractors are used, we manage them and require that they comply with our work policies and QHSE systems.
ITEM 1A. Risk Factors.

Our business, financial position, results of operations or liquidity could be adversely affected by any of these risks. The risks and uncertainties we describe are not the only ones facing us. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business or operations. Any adverse effect on our business, financial position, results of operations or liquidity could result in a decline in the value of our common stock and other securities.

Risks Relating to Our Business and Industry
 
Our business largely depends on the levels of exploration and development activity in the oil and natural gas industry, a historically cyclical industry. A decrease in this activity caused by low oil and natural gas prices, increased supply, and reduced demand, such as has occurred over the last several years, has had an adverse effect on our business, liquidity and results of operations.
 

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Demand for our services depends upon the level of spending by oil and natural gas companies for exploration, production, development and field management activities, which depend, in part, on oil and natural gas supplies and prices. The markets for oil and natural gas have historically been volatile and are likely to continue to be so in the future. In addition to the market prices of oil and natural gas, our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control. A decline in oil and natural gas exploration activities and commodity prices, as has occurred over the last several years, has adversely affected the demand for our services and our results of operations.
 
Factors affecting the prices of oil and natural gas and our customers’ desire to explore, develop and produce include:
the level of supply and demand for oil and natural gas;
expectations about future prices for oil and natural gas;
the worldwide political, military and economic conditions;
the ability of the Organization of Petroleum Exporting Countries to set and maintain production levels and prices for oil;
the rate of discovery of new oil and natural gas reserves and the decline of existing oil and natural gas reserves;
the cost of exploring for, developing and producing oil and natural gas;
the ability of exploration and production companies to generate funds or otherwise obtain capital for exploration, development and production operations;
technological advances affecting energy exploration, production and consumption;
government policies, including environmental regulations and tax policies, regarding the exploration for, production and development of oil and natural gas reserves, the use of fossil fuels and alternative energy sources and climate change;
weather conditions, including large-scale weather events such as hurricanes that affect oil and natural gas operations over a wide area or affect prices; and
changes in the Alaskan oil and gas tax credit system which may significantly affect the level of exploration spending within Alaska and has negatively affected our current liquidity position.
Since the third quarter of 2014, oil prices have declined significantly due in large part to increasing supplies, weakening demand growth, some oil and gas producing countries' position to not cut production and the lifting of sanctions against Iran. While the price of crude oil has recovered from its low, it still has not reached pre-2014 prices.

As a result of these decreases in crude oil prices, many E&P companies have reduced their capital expenditures, which has resulted in diminished demand for our services and products and downward pressure on the prices we charge or the level of work we do for our customers.

We cannot assure you that the exploration and development activities by our customers will be maintained at current levels. Any significant decline in exploration or production-related spending by our customers, whether due to a decrease in the market prices for oil and natural gas or otherwise, would have a material adverse effect on our results of operations. Additionally, increases in oil and natural gas prices may not increase demand for our products and services or otherwise have a positive effect on our results of operations or financial condition.
 
Our revenues are subject to fluctuations that are beyond our control, which may be significant and could adversely affect our results of operations in any financial period.
 
Our operating results may vary in material respects from quarter to quarter. Factors that cause variations include the timing of the receipt and commencement of contracts for seismic data acquisition, processing or interpretation and customers’ budgetary cycles, all of which are beyond our control. In addition, in any given period, we could have idle crews which result in a significant portion of our revenues, cash flows and earnings coming from a relatively small number of crews. Lower crew utilization rates can be caused by land access permit and weather delays, seasonal factors such as holiday schedules, shorter winter days or agricultural or hunting seasons, and crew repositioning and crew utilization and productivity. Additionally, due to location, type of service or particular project, some of our individual crews may achieve results that constitute a significant percentage of our consolidated operating results. Should any of our crews experience changes in timing or delays due to one or more of these factors, our financial results could be subject to significant variations from period to period. Combined with our fixed costs, these revenue fluctuations could also produce unexpected adverse results of operations in any fiscal period.


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In addition to the above potential fluctuations in our revenue, we may also have significant third-party pass-through costs that are reflected in our revenues but correspond to a very small administrative margin charged to the customer. Therefore, our revenues for certain periods may include a large amount of these third-party charges and can cause our gross profit margin to be lower.

Revenues derived from our projects may not be sufficient to cover our costs of completing those projects or may not result in the profit we anticipated when we entered into the contract.
 
Our revenue is determined, in part, by the prices we receive for our services, the productivity of our crews and the accuracy of our cost estimates. The productivity of our crews is partly a function of external factors, such as weather and third-party delays, over which we have no control. In addition, cost estimates for our projects may be inadequate due to unknown factors associated with the work to be performed and market conditions, resulting in cost over-runs. If our crews encounter operational difficulties or delays, or if we have not correctly priced our services, our results of operation may vary and, in some cases, may be adversely affected.

Our projects are performed on both a turnkey basis where a defined amount and scope of work is provided by us for a fixed price and additional work, which is subject to customer approval, is billed separately, and is performed on a term basis where work is provided by us for a fixed hourly, daily or monthly fee. The relative mix of turnkey and term agreements, as related to our projects, can vary widely from time to time. The revenue, cost and gross profit realized on a turnkey contract can vary from our estimated amount because of changes in job conditions, variations in labor and equipment productivity from the original estimates, and the performance of subcontractors. In addition, if conditions exist on a particular project that were not anticipated in the customer contract such as excessive weather delays, community issues, governmental issues or equipment failure, then the revenue timing and amount from a project can be affected substantially. Turnkey contracts may also cause us to bear substantially all of the risks of business interruption caused by weather delays and other hazards. Those variations, delays and risks inherent in billing customers at a fixed price may result in us experiencing reduced profitability or losses on projects.

The significant fixed costs of our operations could result in operating losses.
 
We are subject to significant fixed operating costs, which primarily consist of depreciation and maintenance expenses associated with our equipment, certain crew costs and interest expense on our outstanding indebtedness. Extended periods of significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays or other causes could negatively affect our results and have a material adverse effect on our financial condition and results of operations because we will not be able to reduce our fixed costs as fast as revenues decline.

Our results of operations could be adversely affected by asset impairments.
 
We periodically review our portfolio of equipment for impairment. A prolonged downturn could affect the carrying value of our equipment or other assets and require us to recognize a loss. We may be required to write down the value of our equipment if the present value of future cash flows anticipated to be generated from the related equipment falls below net book value. A decline in oil and natural gas prices, if sustained, can result in future impairments. Because the impairment of long-lived assets or goodwill would be recorded as an operating expense, such a write-down would negatively affect our net income and may result in a breach of certain of our financial covenants under the terms of the documents governing our indebtedness.

Our working capital needs are difficult to forecast and may vary significantly, which could cause liquidity issues and require us to seek additional financing that we may not be able to obtain on satisfactory terms, or at all.
 
Our working capital needs are difficult to predict with certainty. Our available cash varies in material respects as a result of, among other things, the timing of our projects, our customers’ budgetary cycles and our receipt of payment. In particular, delays in receiving payments on our accounts receivable relating to our Alaskan tax credits discussed below may cause liquidity issues for us in the future. Our working capital requirements may continue to increase, due to contraction in our business or expansion of infrastructure that may be required to keep pace with technological advances. Over time, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. In addition, some of our larger projects require significant upfront costs. We therefore may be subject to significant and rapid increases in our working capital needs that could require us to seek additional financing sources. While we currently have a senior loan facility and a credit facility, and we have reduced our outstanding indebtedness as a result of the Restructurings, we are at our borrowing limits under the senior loan facility and have to obtain lender approval to borrow additional funds under our credit facility. Our current cash flow and liquidity difficulties may impair our ability to obtain other sources of financing, and access to additional sources of financing may not be available on terms acceptable to us, or at all.


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Developments in the State of Alaska and their consequences for the market for exploration tax credits and the impacts of those developments on our cash flow have intensified the negative impact on our current liquidity and cash flow.

At December 31, 2017, our largest accounts receivable from one customer was $78.1 million, representing 93% of total consolidated accounts receivable. This customer was relying on monetization of Alaskan exploration tax credits ("Tax Credits"), which monetization was historically accomplished by receipt of predictable payments from the State of Alaska or from third party financing sources. Due to changed economic and political circumstances in the State of Alaska, however, substantial uncertainty regarding the timing of payments from the State of Alaska has developed, which has affected the availability of funding from other sources, which in turn has affected the timing of our receiving payments on this account receivable. As a result, as of December 31, 2017, we classified the entire receivable from the customer as a long-term accounts receivable totaling $78.1 million, including an additional $42.1 million reclassification to long-term accounts receivable during the quarter ended December 31, 2017.

Due to our customer’s inability to monetize the Tax Credits, our customer assigned $89.0 million of Tax Credits to us as security so that we could seek to monetize these Tax Credits and apply the resulting cash, as monetization occurs, toward our customer’s overdue account receivable. As of December 31, 2017, the State of Alaska has completed its audits of approximately $59.1 million of Tax Credit applications. These audits resulted in our receiving approximately $56.2 million of Tax Credit certificates from the State of Alaska in 2016 and 2017. Subsequent to December 31, 2017, the State of Alaska completed its audit of $8.6 million of Tax Credit applications. This audit and the successful appeal of certain previously disallowed expenses resulted in our receiving an additional $8.3 million and $2.9 million of Tax Credit certificates, for a total of $64.5 million of Tax Credit certificates. In 2018 we expect that the State of Alaska will complete its audit on the last Tax Credit application for approximately $21.3 million.

We recorded a reduction of the accounts receivable balance of $3.5 million and $10.9 million related to the monetization of Tax Credit certificates during the years ended December 31, 2017 and 2016, respectively, from the sale of some of our Tax Credit certificates at a slight discount to an Alaskan producer of oil and gas that used the certificates to satisfy production taxes it owed to the State of Alaska.

We have identified a number of paths to payment of our account receivable. These paths include receiving payment on the account receivable by the following means: (i) receiving cash in payment in full of the Tax Credit certificates from the State of Alaska, (ii) receiving proceeds from the possible issuance by the State of Alaska of bonds to pay its Tax Credit liabilities at a discount, (iii) selling Tax Credit certificates into the secondary market to producers at a discount, (iv) receiving cash from a third party to purchase Tax Credit certificates at what is likely to be a more substantial discount, (v) receiving license fees from additional licenses of the seismic data produced for the customer and (vi) selling some or all the seismic data produced for the customer. There can be no assurance that we will receive payment in full of our accounts receivable from these paths, but we continue to diligently pursue them.

Historically, the State of Alaska annually appropriated the amounts needed to pay all Tax Credit certificates for the prior fiscal year. Falling oil and gas prices have substantially reduced Alaska’s revenue from production taxes resulting in significant Alaskan budget deficits. While the Alaskan legislature has appropriated funds for the last two fiscal years to pay outstanding Tax Credit certificates, the Alaskan Governor has vetoed the line item in each year, and limited the appropriation in the last fiscal year to the statutorily established minimum amount of appropriations. In February 2018 we were advised by the State of Alaska that, so long as the payment is limited to the statutorily established minimum amount, we should not expect to receive any payments until fiscal year 2021 and possibly should not expect to be fully paid until fiscal year 2024. In addition, the Alaskan Department of Revenue has acted to limit the secondary market for Tax Credit certificates by not only slowing down the timing for auditing Tax Credit applications and for making payments, but also by issuing advisory opinions in the third quarter of 2016 and the first quarter of 2017 that, contrary to earlier advice, effectively cut-off the secondary market for Tax Credit certificates. These advisory rulings cut -off using transferred Tax Credit certificates for prior years’ tax obligations and not allowing them to be used to pay taxes owed below the four percent minimum production tax rate. While in mid-2017, the Alaska legislature subsequently reversed the prohibition on using transferred Tax Credit certificates for prior years' obligations, to date transferred Tax Credit certificates cannot be used to go below the four percent floor, and the secondary market remains inactive.

One recent development may accelerate payment of the account receivable. The Governor of Alaska has introduced legislation to allow Alaska to issue bonds to pay-off at a discount its approximately $1.2 billion liability for Tax Credits. There can be no assurance, however, that this alternative will provide a viable means to monetize our Tax Credit certificates.

We continue to explore all the options described above to monetize the Tax Credit certificates. We continue to believe that selling the certificates at a discount to producers that are able to apply the certificates to reduce their own Alaskan tax liabilities should yet again become a viable monetization option. We have a contract with a producer that provides that the producer will purchase our Tax Credit certificates to the extent that it can use them to satisfy its tax liabilities. In December 2017 the active Alaskan

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producers agreed to a $786 million settlement regarding tariffs relating to the Trans Alaskan pipeline with FERC, which was approved by FERC in March 2018 that will result in significantly increased production taxes being owed by the producers to the State of Alaska. Those taxes could be satisfied by purchase of Tax Credit certificates at a discount to the face value of the Tax Credit certificate. Alternatively we could sell our Tax Credit certificates to other third parties, at a discount. We also believe that rising oil prices may increase the market for the Tax Credit certificates, but there can be no assurance that prices will increase sufficient to improve the market or when it might occur.
 
We have other possible ways to receive payments on its account receivable that do not involve monetization of the Tax Credits. We continue to assist the customer in actively marketing and licensing of the seismic data we collected on behalf of our customer. Licensing revenues received must be paid to us in satisfaction of our account receivable.   In addition, subject to any licenses granted, our customer has the right to sell the data and apply the proceeds to our receivable.  We believe that the receipt of these licensing revenues and sales proceeds may be sufficient to cover the difference between the outstanding account receivable and the cash we are able to generate by monetization of the Tax Credits, but there can be no assurance that it will occur or when any such payments will be received.

A risk exists that any monetization of the Tax Credit certificates will require a selling at a discount, and that the discount may be substantial, resulting in proceeds insufficient to fully repay the customer’s outstanding account receivable. Should this result, and we do not receive additional payments from our customer from either licensing or selling the seismic data, we may be required to record an impairment to the amount due from our customer, which may materially and adversely affect us.

As part of the 2016 Restructuring, we entered into a senior loan facility, which added up to $30.0 million in additional liquidity. The senior loan facility is secured by a junior first lien on our accounts receivable, which includes the Tax Credits and certificates evidencing the Tax Credits. Those Tax Credits and certificates are also pledged on a senior first lien basis to the lender under our credit facility. All proceeds from monetizing the Tax Credits or Tax Credit certificates are paid into an account at the lender under the credit facility and automatically reduce the amount we have borrowed under that line of credit. The senior loan facility requires that once we have received $15 million in proceeds from the Tax Credits or Tax Credit certificates, unless waived by the lenders (or individual lenders) under the senior loan facility, mandatory repayments of the amount received for the Tax Credits or Tax Credit certificates must be made. As a result, once we have received $15 million in proceeds from the Tax Credits or Tax Credit certificates, and until the outstanding balance on the senior loan facility is paid in full, the amount owed to the lender under the senior loan facility must come from cash or from a borrowing of the amount under our credit facility. Currently, however, we have borrowed the full amount that is committed under the credit facility.

Until we are able to finally resolve the issue described above, we may continue to experience liquidity and cash flow issues. The Restructurings, provided significant levels of short term liquidity, which should mitigated the acuteness of this issue, but there can be no assurance that they will solve the issue of our need to monetize our Tax Credit certificates.

Our operations are subject to weather and seasonality, which may affect our ability to timely complete projects.
 
Our seismic data acquisition services are performed outdoors and often in difficult or harsh climate conditions, and are therefore subject to weather and seasonality. In Canada and Alaska, the primary season for seismic data acquisition is during the winter, from December to April, as many areas are only accessible when the ground is frozen. The weather conditions during this time of year can affect the timing and efficiency of operations. In addition, this prime season can be shortened by warmer weather conditions.

In South America and Southeast Asia, our operations are affected by the periods of heavy rain in the areas where seismic operations are conducted. In all areas in which we operate, the weather is an uncontrollable factor that affects our operations at various times of the year. Due to the unpredictability of weather conditions, there may be times when adverse conditions may cause our operations to be delayed and result in additional costs and may negatively affect our results of operations.

Our operations are subject to delays related to obtaining government permits and land access rights from third parties which could result in delays affecting our results of operations.
 
Our seismic data acquisition operations could be adversely affected by our inability to obtain timely right of way usage from both public and private land and/or mineral owners. We cannot begin surveys on property without obtaining any required permits from governmental entities as well as the permission of the private landowners who own the land being surveyed. In recent years, it has become more difficult, costly and time-consuming to obtain access rights of way as drilling activities have expanded into more populated areas. Additionally, while landowners generally are cooperative in granting access rights, some have become more resistant to seismic and drilling activities occurring on their property. In addition, governmental entities do not always grant permits

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within the time periods expected. Delays associated with obtaining such permits and rights of way may negatively affect our results of operations.

Our backlog can vary significantly from time to time and our backlog estimates are based on certain assumptions and are subject to unexpected adjustments and cancellations and thus may not be timely converted to revenues in any particular fiscal period, if at all, or be indicative of our actual operating results for any future period.

Our backlog estimates represent those projects for which a customer has executed a contract or signed a binding letter of award. Our backlog can vary significantly from time to time, particularly if the backlog is made up of multi-year contracts with some of our more significant customers. Backlog estimates are based on a number of assumptions and estimates including assumptions related to foreign exchange rates and proportionate performance of contracts. The realization of our backlog estimates is further affected by our performance under term rate contracts, as the early or late completion of a project under term rate contracts will generally result in decreased or increased, as the case may be, revenues derived from those projects. Contracts for services are also occasionally modified by mutual consent and often can be terminated for convenience by the customer. Because of potential changes in the scope or schedule of our customers’ projects, and the possibility of early termination of customer contracts, we cannot predict with certainty when or if our backlog will be realized. Material delays, payment defaults or cancellations on the underlying contracts could reduce the amount of backlog currently reported and, consequently, could inhibit the conversion of that backlog into revenues. In addition, worsening overall market conditions could result in further reductions of backlog which will impact our financial performance.

We face intense competition in our business that could result in downward pricing pressure and the loss of market share.
 
Competition among seismic contractors historically has been, and likely will continue to be, intense. Competitive factors have in recent years included price, crew experience, asset availability and capacity, technological expertise and reputation for quality and dependability. We also face increasing competition from nationally owned companies in various international jurisdictions that operate under less significant financial constraints than those we experience. Many of our competitors have greater financial and other resources, more customers, greater market recognition and more established relationships and alliances in the industry than we do. They and other competitors may be better positioned to withstand and adjust more quickly to volatile market conditions, such as fluctuations in oil and natural gas prices and production levels, as well as changes in government regulations. Additionally, the seismic data acquisition business is extremely price competitive and has a history of protracted periods of months or years where seismic contractors under financial duress bid jobs at unattractive pricing levels and therefore adversely affect industry pricing. Competition from those and other competitors could result in downward pricing pressure, which could adversely affect our margins, and could result in the loss of market share.

Capital requirements for the technology we use can be significant. If we are unable to finance these requirements, we may not be able to maintain our competitive advantage.
 
Seismic data acquisition technologies historically have steadily improved and progressed, and, over the long-term, we expect this trend to continue. Manufacturers of seismic equipment may develop new systems that have competitive advantages relative to systems now in use that either render the equipment we currently use obsolete or require us to make substantial capital expenditures to maintain our competitive position. In order to remain competitive, we may need to continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities.

Our capital requirements, which are primarily the cost of equipment, historically have been significant. We attempt to minimize our capital expenditures by restricting our purchase of equipment to equipment that we believe will remain highly utilized, and we strategically rent equipment utilizing the most current technology to cover peak periods in equipment demands. We may not be able to finance all of our capital requirements, however, when and if needed, to acquire new equipment. If we are unable to do so, there may be a material negative impact on our operations and financial condition. Under our current business model, however, capital expenditures will be kept at minimum levels, other than for maintenance expenditures, until we see improvement in the market for seismic services. While we own or can rent the equipment needed for our current levels of business, long-term limiting our capital expenditures may result in an increased competitive disadvantage.

Our revenues are generated by a concentrated number of customers.
 
We derive our revenues from a concentrated customer base in the international oil and natural gas industry. Although we historically have not been dependent on any one customer, recently we had one customer that has represented a significant portion of our accounts receivable. Our largest customers can and typically do change from year to year and our largest customers in any one year may not be indicative of our largest customers in the future. If any of our customers were to terminate their contract with us on a large project or fail to contract for our services in the future because they are acquired, alter their exploration or development

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strategy, experience financial difficulties, as a result of concerns over our current cash flow and liquidity difficulties or for any other reason, and we were not able to replace their business with business from other customers, our business, financial condition and results of operations could be materially and adversely affected.
 
We operate under hazardous conditions that subject us and our employees to risk of damage to property or personal injury and limitations on our insurance coverage may expose us to potentially significant liability costs.
 
Our activities are often conducted in dangerous environments and include hazardous conditions, including operation of heavy equipment, the detonation of explosives, and operations in remote areas of developing countries. Operating in such environments, and under such conditions, carries with it inherent risks, such as loss of human life or equipment, as well as the risk of downtime or reduced productivity resulting from equipment failures caused by an adverse operating environment. Those risks could cause us to experience injuries to our personnel, equipment losses, and interruptions in our business.

Although we maintain insurance, our insurance contains certain coverage exclusions and policy limits. There can be no assurance that our insurance will be sufficient or adequate to cover all losses or liabilities or that insurance will continue to be available to us on acceptable terms, or at all. Further, we may experience difficulties in collecting from insurers as such insurers may deny all or a portion of our claims for insurance coverage. A claim for which we are not fully insured, or which is excluded from coverage or exceeds the policy limits of our applicable insurance, could have a material adverse effect on our financial condition.

We may be held liable for the actions of our subcontractors.
 
We often work as the general contractor on seismic data acquisition surveys and consequently engage a number of subcontractors to perform services and provide products. While we generally obtain contractual indemnification and insurance covering the acts of those subcontractors, and require the subcontractors to obtain insurance for our benefit, there can be no assurance we will not be held liable for the actions of those subcontractors. In addition, subcontractors may cause damage or injury to our personnel and property that is not fully covered by insurance or by claims against the subcontractors.
 
Our agreements with our customers may not adequately protect us from unforeseen events or address all issues that could arise with our customers. The occurrence of unforeseen events or disputes with customers could result in increased liability, costs and expenses for our projects.
 
We enter into master service agreements with many of our customers that allocate certain operational risks. Despite the inclusion of risk allocation provisions in our agreements, our operations may be affected by a number of events that are unforeseen or not within our control and our agreements may not adequately protect us from each possible event. If an event occurs which we have not contemplated or otherwise addressed in our agreement we, and not our customer, will likely bear the increased cost or liability.

To the extent our agreements do not adequately address those and other issues, or we are not able to successfully resolve resulting disputes, we may incur increased liability, costs and expenses. This may have a material adverse effect on our results of operations.
 
We, along with our customers, are subject to compliance with governmental laws and regulations that may expose us to significant costs and liabilities and may adversely affect the demand for our services.
 
Our operations, and those of our customers, are subject to a variety of federal, provincial, state and local laws and regulations in the United States and foreign jurisdictions, including stringent laws and regulations relating to protection of the environment, particularly those relating to emissions to air, discharges to water, treatment, storage and disposal of regulated materials and remediation of soil and groundwater contamination. Those laws and regulations may impose numerous obligations that are applicable to our operations including:
the acquisition of permits before commencing regulated activities; and
the limitation or prohibition of seismic activities in environmentally sensitive or protected areas such as wetlands or wilderness areas.
Numerous governmental authorities, such as the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies in the United States and governmental bodies with control over environmental matters in foreign jurisdictions, have the power to enforce compliance with those laws and regulations and any permits issued under them, oftentimes requiring difficult and costly actions. We may incur substantial costs, including fines, damages, criminal or civil sanctions, remediation costs and natural resource damage claims, or experience interruptions in our operations for violations or liabilities arising under these laws and regulations. Further, we may become liable for damages against which we cannot adequately insure or against which we may elect not to insure because of high costs or other reasons. Our customers are subject to similar environmental laws and regulations.

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We expend financial and managerial resources to comply with all the laws and regulations applicable to our operations. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly regulations, or that change waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position. The fact that such laws or regulations change frequently makes it impossible for us to predict the cost or impact of such laws and regulations on our future operations. The costs of complying with applicable environmental laws and regulations are likely to increase over time and we cannot provide any assurance that we will be able to remain in compliance with respect to existing or new laws and regulations or that such compliance will not have a material adverse effect on our business, financial condition and results of operations, or on the operations of our customers which could affect demand for our services. Although regulatory developments that may occur in subsequent years could have the effect of reducing industry activity, we cannot predict the nature of any new restrictions or regulations that may be imposed. We may be required to increase operating expenses or capital expenditures in order to comply with any new restrictions or regulations.
  
In addition, as a result of the mobility of our equipment, operations in foreign jurisdictions and the utilization of a multi-national work force, we and our customers are subject to various federal, provincial, state and local laws and regulations in the United States and foreign jurisdictions relating to the import or export of equipment and the immigration and employment of non-citizen employees or sub-contractors. Numerous governmental authorities, such as the U.S. Customs and Border Protection, the Bureau of Industry and Security and the Office of Foreign Assets Control, and analogous governmental bodies in foreign jurisdictions have laws and regulations which prohibit or restrict operations in certain jurisdictions and doing business with certain persons in such jurisdictions, and we and our customers may be required to obtain and maintain licenses, permits, visas and similar documentation for operations. We may incur substantial costs, including fines and damages, criminal or civil sanctions for violations or liabilities arising under these laws and regulations.

Our operations outside of the United States are subject to additional political, economic, and other risks and uncertainties that could adversely affect our business, financial condition, results of operations, or cash flows, and our exposure to such risks will increase as we expand our international operations.
 
Our operations outside of North America accounted for a substantial portion of our consolidated revenue. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, and especially those operating in emerging markets. As we continue to increase our presence in those countries, our operations will continue to encounter the following risks, among others:

government instability or armed conflict, which can cause our potential customers to withdraw or delay investment in capital projects, thereby reducing or eliminating the viability of some markets for our services;
potential expropriation, seizure, nationalization or detention of assets;
risks relating to foreign currency, as described below;
import/export quotas or unexpected changes in regulatory environments and trade barriers;
civil uprisings, riots and war, which can make it unsafe to continue operations, adversely affect both budgets and schedules and expose us to losses;
availability of suitable personnel and equipment, which can be affected by government policy, or changes in policy, which limit the importation of qualified crew members or specialized equipment in areas where local resources are insufficient, and legal restrictions or other limitations on our ability to dismiss employees;
laws, regulations, decrees and court decisions under legal systems that are not always fully developed and that may be retroactively applied and cause us to incur unanticipated and/or unrecoverable costs, as well as delays which may result in real or opportunity costs; and
terrorist attacks, including kidnappings of our personnel.
If any of those or other similar events should occur, it could have a material adverse effect on our financial condition and results of operations.

We are subject to taxation in many foreign jurisdictions and the final determination of our tax liabilities involves the interpretation of the statutes and requirements of taxing authorities worldwide. Our tax returns are subject to routine examination by taxing authorities, and those examinations may result in assessments of additional taxes, penalties and/or interest.


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Our overall success as a global business depends, in part, upon our ability to succeed in differing economic, social and political conditions. We may not succeed in developing and implementing policies and strategies that are effective in each location where we do business, and we may experience project disruptions and losses, which could negatively affect our profitability.

Our results of operations can be significantly affected by foreign currency fluctuations and regulations.

A portion of our revenues is derived in the local currencies of the foreign jurisdictions in which we operate. Accordingly, we are subject to risks relating to fluctuations in currency exchange rates. In the future, and especially as we further expand our operations in international markets, our customers may increasingly make payments in non-U.S. currencies. Fluctuations in foreign currency exchange rates could affect our revenues, operating costs and operating margins. In addition, currency devaluation can result in a loss to us if we hold deposits of that currency. Hedging foreign currencies can be difficult, especially if the currency is not actively traded. We cannot predict the effect of future exchange rate fluctuations on our operating results.

In addition, we are subject to risks relating to governmental regulation of foreign currency, which may limit our ability to:
transfer funds from or convert currencies in certain countries;
repatriate foreign currency received in excess of local currency requirements; and
repatriate funds held by our foreign subsidiaries to the United States at favorable tax rates.
As we continue to develop our operations in foreign countries, there is an increased risk that foreign currency controls may create difficulty in repatriating profits from foreign countries in the form of taxes or other restrictions, which could restrict our cash flow.

Economic and political conditions in Latin America pose numerous risks to our operations.

Our business operations in the Latin American region constitute a material portion of our business. As events in the region have demonstrated, negative economic or political developments in one country in the region can lead to or exacerbate economic or political instability elsewhere in the region. Furthermore, events in recent years in other developing markets have placed pressures on the stability of the currencies of a number of countries in Latin America in which we operate, including Brazil, Colombia and Peru. While certain areas in the Latin American region have experienced economic growth, this recovery remains fragile.

Certain Latin American economies have experienced shortages in foreign currency reserves and have adopted restrictions on the use of certain mechanisms to expatriate local earnings and convert local currencies into U.S. Dollars. Any such shortages or restrictions may limit or impede our ability to transfer or to convert such currencies into U.S. Dollars and to expatriate such funds for the purpose of making timely payments of interest and principal on our indebtedness. In addition, currency devaluations in one country may have adverse effects in another country. Some Latin American countries have historically experienced high rates of inflation. Inflation and some measures implemented to curb inflation have had significant negative effects on the economies of these countries. Governmental actions taken in an effort to curb inflation, coupled with speculation about possible future actions, have contributed to economic uncertainty at times in most Latin American countries. These countries may experience high levels of inflation in the future that could lead to further government intervention in the economy, including the introduction of government policies that could adversely affect our results of operations. In addition, if any of these countries experience high rates of inflation, we may not be able to adjust the price of our services sufficiently to offset the effects of inflation on our cost structures. A high inflation environment would also have negative effects on the level of economic activity and employment and adversely affect our business, results of operations and financial condition.

Current and future legislation or regulation relating to climate change and hydraulic fracturing could negatively affect the exploration and production of oil and gas and adversely affect demand for our services.
 
In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHG”) (including carbon dioxide and methane), may be contributing to global climate change, legislative and regulatory measures to address the concerns are in various phases of discussion or implementation at the federal, state and international levels. Many states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs.

This increasing focus on global warming may result in new environmental laws or regulations that may negatively affect us and our customers. This could cause us to incur additional direct costs in complying with any new environmental regulations, as well as increased indirect costs resulting from our customers incurring additional compliance costs that get passed on to us. Moreover, passage of climate change legislation or other legislative or regulatory initiatives that regulate or restrict emissions of GHG may curtail production and demand for fossil fuels such as oil and natural gas in areas where our customers operate and thus adversely

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affect future demand for our services. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Hydraulic fracturing is an important and commonly used process in the completion of oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and natural gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing, legislative and regulatory efforts at the federal level and in some states, have been initiated to require or make more stringent the permitting, reporting and compliance requirements for hydraulic fracturing operations. These legislative and regulatory initiatives imposing additional reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult or costly to complete oil and natural gas wells. Shale gas and shale oil cannot be economically produced without extensive fracturing. In the event such initiatives are successful, demand for our seismic acquisition services may be adversely affected.

As a company subject to compliance with the Foreign Corrupt Practices Act (the “FCPA”), our business may suffer because our efforts to comply with U.S. laws could restrict our ability to do business in foreign markets relative to our competitors who are not subject to U.S. law. Any determination that we or our foreign agents have violated the FCPA may adversely affect our business, operations and reputation.
 
We operate in certain parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence or using other methods that U.S. law and regulations prohibit us from using.

As a U.S. corporation, we are subject to the regulations imposed by the FCPA, which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and which imposes stringent recordkeeping requirements. In particular, we may be held liable for actions taken by our strategic or local partners even though our partners are not subject to the FCPA. Any such violations could result in substantial civil and/or criminal penalties and might adversely affect our results of operations and our ability to continue to work in those countries.

The enactment of legislation implementing changes in U.S. or foreign tax laws affecting the taxation of international business activities or the adoption of other tax reform policies could materially impact our financial position and results of operations.

Changes to U.S. or foreign tax laws could impact the tax treatment of our foreign earnings. Due to the scope of our international business operations, any changes in the U.S. or foreign taxation of these operations may increase our worldwide effective tax rate and adversely affect our financial condition and operating results. The international scope of our operations and our corporate and financing structure may expose us to potentially adverse tax consequences. We are subject to taxation in and to the tax laws and regulations of multiple jurisdictions as a result of the international scope of our operations and our corporate and financing structure. We are also subject to intercompany pricing laws, including those relating to the flow of funds between our companies. Adverse developments in these laws or regulations, or any change in position regarding the application, administration or interpretation of these laws or regulations in any applicable jurisdiction, could have a material adverse effect on our business, financial condition and results of operations. In addition, the tax authorities in any applicable jurisdiction, including the United States, may disagree with the positions we have taken or intend to take regarding the tax treatment or characterization of any of our transactions, including the tax treatment or characterization of our indebtedness, intercompany loans and guarantees. If any applicable tax authorities, including the U.S. tax authorities, were to successfully challenge the tax treatment or characterization of any of our transactions, it could result in the disallowance of deductions and the imposition of tax withholding.

We may be unable to attract and retain executive officers and skilled and technically knowledgeable employees, which could adversely affect our business.
 
Our continued success depends upon retaining and attracting executive officers and highly skilled employees. A number of our executive officers and employees possess many years of industry experience and are highly skilled, and members of our management team also have relationships with oil and gas companies and others in the industry that are integral to our ability to market and sell our services. Our inability to retain such individuals could adversely affect our ability to compete in the seismic service industry. We may face significant competition for such skilled personnel, particularly during periods of increased demand for seismic services. Although we utilize employment agreements and other incentives to retain certain of our key employees, there is no guarantee that we will be able to retain those personnel.
 
If we do not manage growth and contractions in our business effectively, our results of operations could be adversely affected.
 

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Historically, we have experienced significant growth but for the last several years we have contracted our business in response to the decline in oil and natural gas exploration activities. Both growth and contraction have placed significant demands on our personnel, management, infrastructure and support mechanisms and other resources. We must continue to improve our operational, financial, management, legal compliance and information systems to keep pace with the growth of or contractions in our business. We may also expand through the strategic acquisition of companies and assets. We must plan and manage any acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. If we fail to manage growth of or contractions in our business effectively, our ability to provide services could be adversely affected, which could negatively affect our operating results.

The requirements of being a public company increase our operating expenses and divert management’s attention.
 
As a public company, we are subject to the requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Sarbanes-Oxley Act, the Dodd-Frank Act and other applicable securities rules and regulations. Compliance with these rules and regulations require us to incur significant additional legal, accounting and other expenses that we would not incur if we were not a public company.

The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and operating results. The Sarbanes-Oxley Act and the rules subsequently implemented by the SEC and the national securities exchanges, establish certain requirements for the corporate governance practices of public companies. For example, as a result of becoming a public company, we have additional board committees and are required to maintain effective disclosure controls and procedures and internal control over financial reporting. In order to maintain and, if required, improve our disclosure controls and procedures and internal control over financial reporting to meet this standard, significant resources and management oversight are required. As a result, management’s attention has been and will continue to be diverted from other business concerns, which could harm our business and operating results.

Because we are a smaller reporting company, to date our independent auditor has not been required to issue an attestation report regarding our internal control over financial reporting in the annual reports on Form 10-K that we file with the SEC, and we have been subject to scaled disclosure requirements. We will remain a smaller reporting company as long as the market value of our securities held by non-affiliates is below $75 million, as of the end of our second fiscal quarter each year. If we cease to be a smaller reporting company, our expenses will further increase and additional time will be required of our management to comply with those additional requirements.

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our financial obligations.

While the Restructurings have caused our total debt outstanding to significantly decrease, our high level of indebtedness could still have significant effects on our business. For example, our level of indebtedness and the terms of our debt agreements may: 
increase the risk that we may default on our debt obligations;
require us to use a substantial portion of our cash flow from operations to pay interest and principal on our indebtedness, which would reduce the funds available for working capital, capital expenditures and other general corporate purposes;
limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions and other investments, or general corporate purposes particularly in light of the fact that a substantial portion of our assets have been pledged to secure our indebtedness, which may limit the ability to execute our business strategy;
heighten our vulnerability to downturns in our business, our industry or in the general economy and restrict us from exploiting business opportunities or making acquisitions;
place us at a competitive disadvantage compared to those of our competitors that may have proportionately less debt;
limit management’s discretion in operating our business;
limit our flexibility in planning for, or reacting to, changes in our business, the industry in which we operate or the general economy; and
result in higher interest expense if interest rates increase and we have outstanding floating rate borrowings.
Each of these factors may have a material adverse effect on our business, financial condition and results of operations. Our ability to make payments with respect to our indebtedness will depend on our future operating performance, which will be affected by a broad range of factors, including our ability to monetize our Tax Credits, prevailing economic conditions and financial, business and other factors affecting us and our industry, many of which are beyond our control.
 

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Despite existing debt levels, we may still be able to incur substantially more debt, which would increase the risks associated with our leverage.
 
Even with our existing debt levels, we and our subsidiaries may be able to incur additional debt in the future, including debt under our credit facility. Although the terms of our debt agreements limit our ability to incur additional debt, they do not prevent us from incurring amounts of additional debt. If new debt is added to our current debt levels, however, the risks associated with our leverage may intensify.
 
Our debt agreements impose or may impose significant operating and financial restrictions on us and our subsidiaries that may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.
 
Our debt agreements contain covenants that restrict our and our restricted subsidiaries’ ability to take various actions, such as:

transferring or selling certain assets;
paying dividends or distributions, repaying subordinated indebtedness (if any) or making certain investments or other restricted payments;
incurring or guaranteeing additional indebtedness or, with respect to our restricted subsidiaries, issuing preferred stock;
creating or incurring liens securing indebtedness;
incurring dividend or similar payment restrictions affecting restricted subsidiaries;
consummating a merger, consolidation or sale of all or substantially all our and our restricted subsidiaries’ assets;
entering into transactions with affiliates; and
engaging in a business other than our current business and businesses related, ancillary or complementary, to our current businesses or immaterial businesses.
In addition, the security documents relating to our indebtedness restrict us and our restricted subsidiaries from taking or omitting to take certain actions that would adversely affect or impair in any material respect the collateral securing those obligations. Any future debt may also require us to comply with a number of affirmative and negative covenants in addition to the covenants listed above.

We may be prevented from taking advantage of business opportunities that arise if we fail to meet certain financial ratios or because of the limitations imposed on us by the restrictive covenants under these agreements. In addition, the restrictions contained in our debt agreements may also limit our ability to plan for or react to market conditions or meet capital needs, or may otherwise restrict our activities or business plans and adversely affect our ability to finance our operations, enter into acquisitions, execute our business strategy, effectively compete with companies that are not similarly restricted or engage in other business activities that would be in our interest. In the future, we may incur other debt obligations that might subject us to additional and different restrictive covenants that could also adversely affect our financial and operational flexibility.
 
If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment and the sale of our assets to satisfy our obligations with our lenders. Failure to maintain existing financing or to secure new financing could have a material adverse effect on our liquidity and financial position.
 
If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of those agreements. In the event of a default under those agreements, lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. Borrowings under other debt that contain cross-acceleration or cross-default provisions, may also be accelerated and become due and payable. In addition, substantially all of our debt obligations are secured by a lien on substantially all of our U.S. assets and certain of our foreign assets, including 65% of the equity interests in our first-tier foreign subsidiaries. In the event of foreclosure, liquidation, bankruptcy or other insolvency proceeding relating to us or to our subsidiaries that have guaranteed our debt, holders of our secured indebtedness and our other lenders will have prior claims on our assets. If any of those events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms or without incurring substantial costs. Failure to maintain existing or secure new financing could have a material adverse effect on our liquidity and financial position.

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Risks Relating to Our Securities and the Restructurings
There are limited trading markets for our securities and the market prices of our securities are subject to volatility.
The market price of our common stock, like that of the securities of other energy companies, has been and may continue to be highly volatile. In addition, the volatility and market price of our common stock has been negatively impacted by the significant cash flow and liquidity difficulties that we are currently experiencing. Factors such as announcements concerning changes in prices of oil and natural gas, exploration and development activities, the availability of capital, our cash flow and liquidity situation and negotiations regarding potential restructuring transactions, and economic and other external factors, as well as period-to-period fluctuations and financial results, may have a significant effect on the market price of our common stock. Because our preferred shares and warrants are convertible into shares of our common stock, volatility or depressed prices for our common stock is likely to have a similar effect on the trading price of the preferred shares and warrants, which may make them difficult to resell.
From time to time, there has been limited trading volume in our common stock. In addition, there can be no assurance that there will continue to be an active trading market for our common stock or that any securities research analysts will provide research coverage on our common stock. It is possible that such factors will adversely affect the market for our common stock. After completion of the 2017 Restructuring, we expect there will likely be even less trading in, and greater trading volatility with respect to, our common stock. There is currently no market for, and we do not intend to list, the preferred shares or the warrants issued in the 2017 Restructuring on any securities exchange or any automated dealer quotation system. Accordingly, there may not be development of, or liquidity in, any market for the preferred shares or warrants. If a market were to develop, these securities could trade at prices that may be higher or lower than their initial price depending upon many factors, including the price of our common stock, prevailing interest rates, our operating results and markets for similar securities
Our preferred shares rank junior to all of our indebtedness and other liabilities, have no public market, are subject to restrictions on transfer and have limited voting rights.
In the event of our bankruptcy, liquidation, reorganization or other winding-up, our assets will be available to pay obligations on the preferred shares only after all of our indebtedness and other liabilities have been paid. Consequently, if we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets remaining to pay amounts due on the preferred shares then outstanding.
Neither the preferred shares nor the shares of our common stock issuable upon conversion of the preferred shares have been registered under the Securities Act and we do not intend to file a registration statement for the resale of the preferred shares. The restrictions on transfer applicable to the preferred shares may affect the ability to resell such securities or reduce the price that may be received in doing so.
The preferred shares do not have voting rights, except under limited circumstances such as under Delaware law or if the action involves the authorization or issuance of any class or series of senior stock or parity stock and for amendments to our certificate of incorporation by merger or otherwise that would affect adversely the rights of holders of the preferred shares including dividends thereon, the liquidation preference, redemption and conversion rights, ranking and certain other protections, including an anti-layering provision and certain consent rights with respect to the granting of liens on the Alaska Tax Credits (other than the liens granted to secure obligations under our credit facilities).
The Restructurings significantly altered our capital structure but may not solve our liquidity problems.
As a result of our Restructurings, our capital structure has been substantially improved but there can be no assurance that we will not have any additional capital structure or liquidity issues. Moreover, our continued implementation of restructuring and cost saving initiatives may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not expect to pay dividends on our common stock in the near future and, while the preferred stock pays dividends, we are not obligated to pay them unless our board declares them.
We do not anticipate that cash dividends or other distributions will be paid on our common stock in the foreseeable future. In addition, restrictive covenants in certain debt agreements to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

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We are not obligated to pay dividends on our Series B Preferred Stock and no payment or adjustment will be made upon conversion for accumulated dividends. Dividends on the Series B Preferred Stock are only payable when, as and if declared by our board, but our board is not legally obligated to do so. Further, our current indebtedness and any indentures and other financing agreements that we enter into in the future may limit our ability to pay dividends on our capital stock, including the preferred stock, in which case we will be unable to pay dividends on the preferred stock unless we can refinance amounts outstanding under those agreements. For example, our credit facility and senior loan facility contain certain restrictions on our ability to make cash dividend payments.
Under Delaware law, dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from a company’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay cash dividends on the preferred stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of our net assets over our capital. Further, even if adequate surplus is available to pay dividends on the preferred stock, we may not have sufficient cash to pay such dividends.
Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our certificate of incorporation and bylaws may have the effect of delaying or preventing changes in control if our board determines that such changes in control are not in our best interests and in the best interests of our stockholders. Those provisions in our certificate of incorporation and bylaws include, among other things, those that:
limit the ability of stockholders to nominate or remove directors;
authorize our board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
limit the persons who may call special meetings of stockholders.
While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our board, they could enable the board to hinder or frustrate a transaction that some stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board, which is responsible for appointing the members of our management.



25


ITEM 2. Properties.
 
Properties
 
We lease all of the facilities used in our operations. Our principal facilities are summarized in the table below. 
Location
 
Square Footage
 
Purpose
Houston, Texas, U.S.A.
 
7,454
 
Executive offices
Calgary, Alberta, Canada
 
9,008
 
Executive offices
Calgary, Alberta, Canada
 
15,000
 
Warehouse
Anchorage, Alaska, U.S.A.
 
4,800
 
Field Office
Anchorage, Alaska, U.S.A.
 
7,524
 
Warehouse
Lima, Peru
 
4,112
 
Field Office
Lima, Peru
 
9,235
 
Warehouse
Iquitos, Peru
 
24,757
 
Warehouse
Bogotá, Colombia
 
2,629
 
Field Office
Bogotá, Colombia
 
34,821
 
Warehouse
Santa Cruz, Bolivia
 
5,382
 
Field Office
Santa Cruz, Bolivia
 
15,069
 
Warehouse
Rio de Janeiro, Brazil
 
452
 
Field Office
 
The leases expire at various times over the next seven years and most contain renewal options for additional one-year periods. The leases generally require us to pay all operating costs, such as maintenance, property taxes and insurance. We believe that our facilities are generally well maintained and adequate to meet our current and foreseeable requirements for the next several years.

ITEM 3. Legal Proceedings.
 
In the ordinary course of business, we may be subject to legal proceedings involving contractual and employment relationships, liability claims and a variety of other matters. Although the results of these other legal proceedings cannot be predicted with certainty, we do not believe that the final outcome of these matters should have a material adverse effect on our business, results of operations, cash flows or financial condition.

PART II

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Price of Common Stock and Warrants
 
Our common stock is traded on the Nasdaq Capital Market under the symbol “SAEX.” Originally, we were traded on the Nasdaq Global Market. In 2016 we received certain deficiency notices from the Nasdaq Global Market stating that we had not met certain continued listing standards. In January 2017, we received notification from the Nasdaq Global Market that we had regained compliance. In August 2017, we changed to being traded on the Nasdaq Capital Market. All share prices for common stock reflect the 135-for-1 reverse stock split, which was effective July 26, 2016.

Our 2011 warrants were quoted on the Over-the-Counter Bulletin Board under the symbol “SAEXW” prior to their expiration. on June 24, 2016 (the "Expired Warrants"). No Expired Warrants remained outstanding after that date. As a part of the 2016 Restructuring, we issued Series A Warrants and Series B Warrants to holders of common stock of record on July 26, 2016. While our Series A Warrants and the Series B Warrants are quoted on the Over-the Counter Bulletin Board under the symbol "SXPLW", there is currently no established public trading market for them. In addition, there is no established public market for our Series A Preferred Stock, Series C Warrants or Series D Warrants issued as a result of our 2017 Restructuring.

The following table sets forth the high and low sales prices for the common stock and bid prices for the Expired Warrants for the periods indicated:

26


 
Common Stock
 
Expired Warrants
 
High
 
Low
 
High
 
Low
Fiscal 2017:
 

 
 

 
 

 
 

Fourth Quarter
$
2.95

 
$
1.18

 
N/A

 
N/A

Third Quarter
$
3.50

 
$
1.50

 
N/A

 
N/A

Second Quarter
$
6.62

 
$
3.03

 
N/A

 
N/A

First Quarter
$
8.25

 
$
4.41

 
N/A

 
N/A

Fiscal 2016:
 
 
 
 
 
 
 
Fourth Quarter
$
12.17

 
$
6.02

 
N/A

 
N/A

Third Quarter
$
75.00

 
$
6.32

 
N/A

 
N/A

Second Quarter
$
118.80

 
$
16.20

 
$
8.10

 
$
2.70

First Quarter
$
271.35

 
$
89.10

 
$
8.10

 
$
8.10


Holders
 
As of March 9, 2018, there were 110 holders of record of our common stock. Based upon individual participants in certain position listings, we believe there are more than 1,100 beneficial owners of our common stock. As of March 9, 2018, there was one holder of record of the Series A Preferred Stock and we estimate approximately 33 beneficial owners of our Series A Preferred Stock. Due to the mandatory conversion of the Series B Preferred Stock on March 6, 2018, as of March 9, 2018, there were no holders of such preferred shares. Due to the expiration of the Expired Warrants on June 26, 2016, there are no holders of record of such warrants. As of March 9, 2018 there were 74 holders of record of each of the Series A Warrants and Series B Warrants, one holder of record of the Series C Warrants and 14 holders of record of the Series D Warrants. We estimate there are approximately 35 beneficial owners of our Series C Warrants.

Dividends
 
We have not paid any cash dividends on our common stock to date and it is the present intention of our board of directors to retain all earnings, if any, for use in our business operations and, accordingly, our board does not anticipate declaring any dividends on our common stock in the foreseeable future. Commencing April 1, 2018, our Series A Preferred Stock has an 8% dividend payable quarterly in arrears and whether or not earned or declared under certain circumstances, at our option, dividends may be paid in the form of additional shares of Series A Preferred Stock. See Note 13 to the Consolidated Financial Statements for further discussion regarding the terms of our Series A Preferred Stock.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes to those statements included in this report. This discussion contains forward-looking statements that involve risks and uncertainties. Please see the sections entitled “Cautionary Note regarding Forward-Looking Statements” and “Risk Factors” in this report.

Introduction
 
We are an internationally-focused oilfield services company offering a full range of vertically-integrated seismic data acquisition and logistical support services in Alaska, Canada, South America, Southeast Asia and West Africa to our customers in the oil and natural gas industry. We were initially formed on February 2, 2011 as a blank check company in order to effect a merger, capital stock exchange, asset acquisition or other similar business combination with one or more business entities. On June 24, 2013, our wholly-owned subsidiary completed the Merger with Former SAE, at which time the business of Former SAE became our business.

The Merger was accounted for as a reverse acquisition in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Under this method of accounting, we were treated as the “acquired” company for financial reporting purposes. This determination was primarily based on Former SAE comprising the ongoing operations of the combined entity, Former SAE senior management comprising the senior management of the combined company, and the Former SAE common stockholders having a majority of the voting power of the combined entity. In accordance with guidance applicable to these circumstances, the Merger was considered to be a capital transaction in substance. Accordingly, for accounting purposes, the Merger was treated as the equivalent of Former SAE issuing stock for our net assets, accompanied by a recapitalization. Our net

27


assets were stated at fair value, with no goodwill or other intangible assets recorded. Operations prior to the Merger are those of Former SAE. The equity structure after the Merger reflects our equity structure.
Overview of our Business
 
Our services include the acquisition of 2D, 3D, time-lapse 4D and multi-component seismic data on land, in transition zones between land and water, and offshore in depths reaching 3,000 meters. In addition, we offer a full suite of logistical support and in-field data processing services. Our customers include major integrated oil companies, national oil companies and independent oil and gas exploration and production companies. Our services are primarily used by our customers to identify and analyze drilling prospects and to maximize successful drilling, making demand for such services dependent upon the level of customer spending on exploration, production, development and field management activities, which is influenced by the fluctuation in oil and natural gas commodity prices. Demand for our services is also impacted by long-term supply concerns based on significant increases in production, national oil policies and other country-specific economic and geopolitical conditions. We have expertise in logistics and focus upon providing a complete service package, particularly in our international operations, which allows efficient movement into remote areas, giving us what we believe to be a strategic advantage over our competitors. Many of the areas of the world where we work have limited seasons for seismic data acquisition, requiring high utilization of key personnel and redeployment of equipment from one part of the world to another. All of our remote area camps, drills and support equipment are easily containerized and made for easy transport to locations anywhere in the world. As a result, if conditions deteriorate in a current location or demand rises in another location, we are able to quickly redeploy our crews and equipment to other parts of the world. By contrast, we tend to subcontract out more of our services in North America than in other regions, and our North American revenues tend to be more dependent upon data acquisition services rather than our full line of services.
While our revenues from services are mainly affected by the level of customer demand for our services, operating revenue is also affected by the bargaining power of our customers relating to our services, as well as the productivity and utilization levels of our data acquisition crews. Our logistical expertise can be a mitigating factor in service price negotiation with our customers, allowing us to maintain larger margins in certain regions of the world, particularly in the most remote or most challenging climates of the world. Factors impacting the productivity and utilization levels of our crews include permitting delays, downtime related to inclement weather, decrease in daylight working hours during winter months, time and expense of repositioning crews, the number and size of each crew, and the number of recording channels available to each crew. We have the ability to optimize the utilization of personnel and equipment, which is a key factor to stabilizing margins in the various regions in which we operate. Specifically, we have invested in equipment that is lighter weight and more easily shipped between the different regions. The ability to reduce both the costs of shipment and the amount of shipping time increases our operating margins and utilization of equipment. Similar logic applies to the utilization of personnel. We focus on employing field managers who are mobile and have the expertise and knowledge of many different markets within our operations. This allows for better timing of operations and the ability of management staff to run those operations while at the same time minimizing personnel costs. An added benefit of a highly mobile field management team is better internal transfer of skill and operational knowledge and the ability to spread operational efficiencies rapidly between the various regions.
Generally, the choice of whether to subcontract out services depends on the expertise available in a certain region and whether that expertise is more efficiently obtained through subcontractors or by using our own labor force. For the most part, services are subcontracted within North America and our personnel are used in other regions where we operate. When subcontractors are used, we manage them and require that they comply with our work policies and QHSE objectives.
Key Accomplishments
 
While the prolonged downturn in the oil and gas industry has had significant effects on our revenue and 2017 was our most challenging year to date, we continue to strive to maximize opportunities for revenue as well as managing our operating margins through cost reductions and field-level efficiencies. We continue to develop our core markets while consistently evaluating opportunities to further expand our geographical footprint, operational capabilities and logistical expertise to provide seismic data acquisition and related services in logistically challenging areas.
Since our progression from providing services exclusively in South America to now operating in North America, West Africa and Southeast Asia, we are able to achieve improved levels of utilization through redeployment of key personnel and seismic equipment from off-season areas to in-season areas, helping reduce some of the peaks and valleys in our financial performance. We anticipate future improvement in long-term financial performance and more consistent operating results as a result of reducing the impact of our otherwise highly seasonal business through such redeployments.

Capital Investments and Impact on Operations 
 

28


During 2017, we made minimal capital expenditures of approximately $2.7 million, primarily related to the purchase of a set of vibrators and additional camp equipment. During 2016, we made capital expenditures of approximately $3.4 million for the purchase of vibrators for our North American operations. Under our current business model, capital expenditures will be kept at minimum levels other than very low maintenance expenditures until we see improvement in the overall oil and natural gas market.
Historically, in line with our focus on wireless land data acquisition, we purchased a wireless seismic data acquisition system which allows up to three crews to operate under the system at the same time. Following customer needs for higher density land programs using a single point receiver application and to answer the demand for conventional and unconventional oil and gas exploration, we purchased high sensitivity geophones and two types of vibrators, further strengthening our position as a full solution provider for land data acquisition methods and technologies. Additional equipment investments were made for ongoing operations in Alaska in order to increase efficiency. We also invested in cable equipment in order to provide customers in South America with reliable systems as wireless technology is slower to take hold in that market.
We will continue to employ our wireless equipment on a worldwide basis while maintaining the ability to provide services to the still existing cable markets. Our capital purchases have allowed us to take advantage of all aspects of the geophysical services market, ranging from land, marine and transition zone data acquisition; 2D, 3D, time lapse 4D and multi-component data acquisition; use of different methods to acquire data such as using vibroseis (vibrating) and impulsive sources; as well as vertical seismic profiling and reservoir monitoring. Any investments in expanding further into our onshore markets in South America and Southeast Asia will likely also focus upon surveying, drilling and base camp operations.
Fiscal 2017 Summary
 
The following discussion is intended to assist in understanding our financial position at December 31, 2017, and our results of operations for the year ended December 31, 2017. Financial and operating results for the year ended December 31, 2017 include:

Revenues from services were $127.0 million in 2017, a decrease of 38.2% from $205.6 million in 2016.
Gross profit was $22.1 million in 2017, a decrease of $23.0 million, or 51.0%, from $45.0 million in 2016.
Operating loss was $3.5 million in 2017, a decrease of $14.8 million, or 131.4%, from operating income of $11.2 million in 2016.
Net loss was $38.8 million in 2017, an increase of $16.8 million in losses, from a net loss of $22.0 million in 2016.
Adjusted EBITDA, which is a non-GAAP figure and defined below, was $11.0 million in 2017, a decrease of 69.7% from $36.1 million in 2016.
Cash and cash equivalents totaled $3.6 million as of December 31, 2017 compared to $11.5 million as of December 31, 2016.
Results of Operations
 
The following section sets forth, for the periods indicated, certain financial data derived from our consolidated statements of operations. Amounts are presented in thousands unless otherwise indicated.

Revenues by Geographic Region

The following table is a summary of our revenues by the geographic region in which we provided services for the years ended December 31, 2017 and 2016:
 
Years Ended December 31,
 
2017
 
% of Revenue
 
2016
 
% of Revenue
 
Increase (Decrease)
 
Percentage Change
Revenue from services:
 
 
 
 
 
 
 
 
 
 
 
North America
$
54,963

 
43.3
%
 
$
86,967

 
42.3
%
 
$
(32,004
)
 
(36.8
)%
South America
32,672

 
25.7
%
 
116,542

 
56.7
%
 
(83,870
)
 
(72.0
)%
Southeast Asia
4,266

 
3.4
%
 
1,734

 
0.8
%
 
2,532

 
146.0
 %
West Africa
35,121

 
27.6
%
 
321

 
0.2
%
 
34,800

 
10,841.1
 %
Total revenue
$
127,022

 
100.0
%
 
$
205,564

 
100.0
%
 
$
(78,542
)
 
(38.2
)%


29


North America: In Alaska, we experienced a significant decrease in the overall number of projects performed in 2017 compared to the same period in 2016. The decrease in activity was mainly due to uncertainties and changes in the state legislation affecting oil and gas exploration activities and tax credits and overall oil and gas market conditions. Revenue in Alaska is primarily all earned in the first fourth months of the year due to weather conditions and the corresponding seasonality of projects. Activity in Canada increased when comparing 2017 to 2016 due to marginal improvement in market conditions in Canada and the timing of the commencement of the season. 

South America: The substantial decrease in revenue during 2017 in South America is primarily due to a large project in Bolivia in 2016 that was substantially completed during the third quarter of 2016 versus having other small projects in Bolivia in 2017. Activity in Colombia decreased in 2017 when compared to 2016 due to a fewer number of active customers resulting in a decrease in revenue.

Southeast Asia: The increase in revenue during 2017 was primarily due to a small project in New Zealand in 2017 versus no active revenue in 2016 in Southeast Asia.

West Africa: The increase in 2017 revenue for West Africa was primarily due to a large ocean bottom marine project in Nigeria which commenced in late December 2016 and was completed during the first quarter of 2017.

Comparison of Operating Results for the Years Ended December 31, 2017 and 2016
 
The following table is a summary of the results of operations for the years ended December 31, 2017 and 2016:
 
Years Ended December 31,
 
2017
 
% of Revenue
 
2016
 
% of Revenue
Revenue from services
$
127,022

 
100.0
 %
 
$
205,564

 
100.0
 %
Gross profit
22,068

 
17.3
 %
 
45,036

 
21.9
 %
Selling, general and administrative expenses
25,697

 
20.2
 %
 
29,253

 
14.2
 %
(Gain) loss on disposal of property and equipment, net
(101
)
 
(0.1
)%
 
4,542

 
2.2
 %
Income (loss) from operations
(3,528
)
 
(2.8
)%
 
11,241

 
5.5
 %
Other expense, net
(30,943
)
 
(24.4
)%
 
(27,194
)
 
(13.2
)%
Provision for income taxes
4,313

 
3.4
 %
 
6,056

 
3.0
 %
Less: net income attributable to noncontrolling interest
1,972

 
1.6
 %
 
3,021

 
1.5
 %
Net loss attributable to the Corporation
$
(40,756
)
 
(32.1
)%
 
$
(25,030
)
 
(12.2
)%

Revenue from Services. Our revenue from services decreased by $78,542 or 38.2%, from $205,564 in 2016 to $127,022 in 2017. As explained above, 2017 revenue decreased significantly in Alaska due to a decrease in the amount of active projects compared to the prior year. In addition, we had a large decrease in South America due to a large project in Bolivia in 2016 that was not repeated in 2017 and decreases in activity in Colombia. These decreases were partially offset by a large ocean bottom marine project in Nigeria that was primarily completed in 2017, and increases in revenues in Southeast Asia and Canada.

Gross Profit. Gross profit decreased by $22,968 or 51.0%, from $45,036 in 2016, representing 21.9% of revenue, to $22,068 in 2017, representing 17.3% of revenue. The decrease in gross profit was largely due to a decrease in active projects in 2017 primarily in Alaska and Bolivia compared to 2016. Gross profit as a percentage of sales decreased slightly due to a decline in revenues resulting in a reduced ability to absorb certain fixed costs and tightening margins on projects. Although our costs primarily vary with revenue, the substantial decrease in revenue we have seen has caused significant decreases in our gross profit and gross profit margins. These decreases were partially offset by an increase in revenues in West Africa due to a large ocean bottom marine project as well as a decrease in depreciation expense due to the sale of ocean bottom nodal equipment in the fourth quarter of 2016.

Adjusted Gross Profit. Adjusted gross profit decreased by $27,653 or 45.0%, from $61,446 in 2016, representing 29.9% of revenue, to $33,793 in 2017, representing 26.6% of revenue. The decrease in adjusted gross profit and adjusted gross profit as a percentage of revenues was due to the decrease in revenues. We have also experienced increased pricing pressure due to the downturn in the oil and gas market, which has caused decreases in our margins.

Selling, General and Administrative Expenses. Selling, general and administrative (“SG&A”) expenses decreased in 2017 by $3,556 to $25,697 or 20.2% of revenues compared to $29,253 or 14.2% of revenues for 2016. SG&A expense decreased due to

30


the decrease in revenue, severance costs and payroll related liabilities partially offset by an increase in share-based compensation expense. The increase in SG&A as a percentage of revenue is due to the substantial decrease in revenue and an increase in share-based compensation expense. SG&A expense for 2016 includes $928 in severance costs incurred in our Peru, Colombia, Canada, Alaska and corporate locations related to the workforce reduction program that began in early 2015.

(Gain) loss on disposal of property and equipment. In 2017, we recorded total net gains on disposal of property and equipment of $101 while in 2016 we recorded a loss of $4,542. This gain is primarily due to the sale of nodal recording equipment and related support gear in Alaska in the fourth quarter of 2016.

Total Other Income (Expense). Total other income (expense) was comprised of the following:
 
Years Ended December 31,
 
2017
 
2016
 
Increase (Decrease)
Other income (expense):
 
 
 
 
 
Costs incurred on restructurings
$

 
$
(5,439
)
 
$
5,439

Interest expense, net
(29,363
)
 
(23,697
)
 
(5,666
)
Foreign exchange gain (loss), net
(1,308
)
 
1,977

 
(3,285
)
Other expense, net
(272
)
 
(35
)
 
(237
)
Total other expense, net
$
(30,943
)
 
$
(27,194
)
 
$
(3,749
)

The increase in 2017 other expense was primarily due to:

Increase in interest expense related to the amortization of deferred financing costs for the senior loan facility;
Decrease in foreign currency gains primarily related to unrealized transactions, in early 2016, related to the weakening US Dollar compared to Canadian and South American currencies creating large gains;
Increase in foreign currency loss due to losses from physical trades of the Nigerian currency for US dollars totaling $1,310; partially offset by
Decrease in costs incurred for the 2016 Restructuring of $5,439.

Income Taxes.   Our income tax provision decreased $1,743 in 2017 compared to 2016 primarily as a result of pre-tax income in our foreign operations, offset by the valuation allowance decrease of $5,761 and the effects of differences between U.S. and foreign tax rates.

We operate in Bolivia,Colombia and Nigeria as subsidiaries or branches of a U.S. entity (whereby the earnings of the branches are included as U.S. taxable income). These subsidiaries or branches are subject to foreign taxation based on the financial results of the operations under the laws of each applicable tax jurisdiction.

Corporate income taxes are calculated based on GAAP and U.S. and various international tax codes and regulations. The appropriate foreign taxes paid in the country of operations are credited against U.S. corporate taxes subject to the U.S. foreign tax credit limitations. Deferred tax assets and liabilities are recognized using the asset and liability method based on the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carry forwards, as stipulated under GAAP. Where appropriate, valuation allowances are provided to reserve the amount of net operating loss and tax credit carry forwards where it is not more likely than not that they will be realized due to various provisions of both U.S. and foreign tax laws.

A comprehensive model is used to account for uncertain tax positions, which includes consideration of how we recognize, measure, present and disclose uncertain tax positions taken or to be taken on a tax return. The income tax laws and regulations are voluminous and are often ambiguous. As such, we are required to make many subjective assumptions and judgments regarding our tax positions that can materially affect amounts recognized in our consolidated balance sheets and statements of operations.

Our U.S. statutory tax rate was 35% for years ended December 31, 2017 and 2016. For 2017, our effective tax rate was (12.5)% due to the effects of differences between U.S. and foreign tax rates, net of federal benefit and recording of the valuation allowance against U.S. and foreign deferred tax assets. For 2016, our effective tax rate was (38.0)% principally due to permanent differences, the effects of differences between U.S. and foreign tax rates, and the recording of the valuation allowances against the U.S. deferred tax assets.

31



Net Income Attributable to Noncontrolling Interest. The $1,049 decrease in 2017 compared to 2016 is due to the decreased income earned by the noncontrolling interest ("Joint Venture Partner") under contracts performed by us on the North Slope of Alaska related to the decrease in Alaska revenue discussed above. Under the terms of our agreement with the Joint Venture Partner, they receive 51% of the portion of the applicable contracts' gross revenues paid to the joint venture entity as discussed further under Note 15 of "Notes to Consolidated Financial Statements".

Net Loss Attributable to the Corporation. For the year ended December 31, 2017, net loss attributable to the Corporation was $40,756 compared to a net loss of $25,030 for the year ended December 31, 2016. The increase in net loss attributable to the Corporation for the year ended December 31, 2017 was primarily due to the following factors:

Lower gross profit primarily due to lower revenue;
Increase in interest expense primarily due to the increase of $6,147 in amortization of deferred financing costs related to our Senior Loan Facility;
Decrease in gains on foreign currency transactions due to large gains in 2016 related to the strengthening US dollar during that time period;
Increase in foreign currency losses due to trades and foreign currency exposure on our project in Nigeria; and
Proportionately higher provision for income taxes in 2016; partially offset by
Decrease in SG&A expenses primarily due to the lower revenue; and
Decrease in costs of debt restructuring of $5,439.

Liquidity and Capital Resources
 
Our principal source of cash is from the seismic data acquisition services we provide to customers, supplemented as necessary by drawing against our credit facility and advances under our senior loan facility. Our cash is primarily used to provide additional seismic data acquisition services, including the payment of expenses related to operations and the acquisition of new seismic data equipment, and to pay the interest on outstanding debt obligations. Our cash position and revenues depend on the level of demand for our services. Historically, cash generated from operations, along with cash reserves and borrowings from commercial, private, and related parties, have been sufficient to fund our working capital and to acquire or lease seismic data equipment. Amounts in the remainder of this section are presented in thousands unless otherwise indicated. References to Notes are to the notes of our consolidated financial statements.
Working Capital.   Working capital as of December 31, 2017 was negative $2,960 compared to positive $40,807 as of December 31, 2016. The decrease in working capital was principally due to the reclassification of $48,100 of accounts receivable from short term to long term related to a customer in Alaska as further discussed in Note 3 and below. The decrease in activity in 2017 and cash used in operations also contributed to a decrease in working capital in 2017.

In September 2017, we entered into the Credit Facility which provides for funding for our working capital needs up to $20,000 subject to our lenders in their sole discretion to fund borrowings exceeding $5,000. It now has a maturity date of January 2, 2020. In addition, we entered into amendments that extended the maturity date of $29,000 of the principal balance of our Senior Loan Facility to January 2, 2020, but that facility is fully drawn. See additional information on these facilities below.

Cash Flows. Cash used by operations during 2017 was $4,553, compared to cash used in operations of $19,830 during 2016, a increase in cash provided by operations of $15,277. Cash used by the net loss and net cash adjustments decreased to $3,424 for 2017 compared to cash provided of $11,042 for 2016, as a result of the increase in net loss in 2017 and decrease in losses on disposal of property and depreciation and amortization expense partially offset by an increase in amortization of deferred financing costs related to our Senior Loan Facility, an increase in payment in kind interest on our Second Lien Notes and a decrease in foreign currency gains. Net changes in operating assets and liabilities resulted in cash used of $1,129 for 2017 compared to cash used of $30,872 for 2016. The significant cash used last year was primarily due to the large increase in unpaid accounts receivable described below and in Note 3. This was partially offset by higher taxes paid than incurred primarily incurred in South America in the year ended December 31, 2017.

At December 31, 2017, our largest accounts receivable from one customer was $78.1 million, representing 93% of total consolidated accounts receivable. This customer was relying on monetization of Tax Credits, which monetization was historically accomplished by receipt of predictable payments from the State of Alaska or from third party financing sources. Due to changed economic and political circumstances in the State of Alaska, however, substantial uncertainty regarding the timing of payments from the State of Alaska has developed, which has affected the availability of funding from other sources, which in turn affected the timing of our receiving payments on this account receivable. As a result, as of December 31, 2017, we classified the entire receivable from the customer as a long-term accounts receivable totaling $78.1 million, including an additional $42.1 million reclassification to

32


long-term accounts receivable during the quarter ended December 31, 2017. As of December 31, 2016, $38.0 million was classified as long-term accounts receivable based on the expected timing to monetize the Tax Credits at that point in time.

Due to our customer’s inability to monetize the Tax Credits, the customer assigned $89.0 million of Tax Credits to us as security so that we could seek to monetize these Tax Credits and apply the resulting cash, as monetization occurs, toward the customer’s overdue account receivable. As of December 31, 2017, the State of Alaska has completed its audits of approximately $59.1 million of Tax Credit applications. These audits resulted in our receiving approximately $56.2 million of Tax Credit certificates from the State of Alaska in 2016 and 2017. Subsequent to December 31, 2017, the State of Alaska completed its audit of $8.6 million of Tax Credit applications. This audit and the successful appeal of certain previously disallowed expenses resulted in our receiving an additional $8.3 million and $2.9 million of Tax Credit certificates, for a total of $64.5 million of Tax Credit certificates. In 2018 we expect that the State of Alaska will complete its audit on the last Tax Credit application for approximately $21.3 million.

We recorded a reduction of the accounts receivable balance of $3.5 million and $10.9 million related to the monetization of Tax Credit certificates during the years ended December 31, 2017 and 2016, respectively, from the sale of some of our Tax Credit certificates at a slight discount to an Alaskan producer of oil and gas that used the certificates to satisfy production taxes it owed to the State of Alaska.

We have identified a number of paths to payment of its account receivable and continue to diligently pursue them. These paths include receiving payment on the account receivable by the following means: (i) receiving cash in payment in full of the Tax Credit certificates from the State of Alaska, (ii) receiving proceeds from the possible issuance by the State of Alaska of bonds to pay its Tax Credit liabilities at a discount, (iii) selling Tax Credit certificates into the secondary market to producers at a discount, (iv) receiving cash from a third party to purchase Tax Credit certificates at what is likely to be a more substantial discount, (v) receiving license fees from additional licenses of the seismic data produced for the customer and (vi) selling some or all the seismic data produced for the customer.

Historically, the State of Alaska annually appropriated the amounts needed to pay all Tax Credit certificates for the prior fiscal year. Falling oil and gas prices have substantially reduced Alaska’s revenue from production taxes resulting in significant Alaskan budget deficits. While the Alaskan legislature has appropriated funds for the last two fiscal years to pay outstanding Tax Credit certificates, the Alaskan Governor has vetoed the line item in each year, and limited the appropriation in the last fiscal year to the statutorily established minimum amount of appropriations. In February 2018 we were advised by the State of Alaska that, so long as the payment is limited to the statutorily established minimum amount, we should not expect to receive any payments until fiscal year 2021 and possibly should not expect to be fully paid until fiscal year 2024. In addition, the Alaskan Department of Revenue has acted to limit the secondary market for Tax Credit certificates by not only slowing down the timing for auditing Tax Credit applications and for making payments, but also by issuing advisory opinions in the third quarter of 2016 and the first quarter of 2017 that, contrary to earlier advice, effectively cut-off the secondary market for Tax Credit certificates. These advisory rulings cut -off using transferred Tax Credit certificates for prior years’ tax obligations and not allowing them to be used to pay taxes owed below the four percent minimum production tax rate. While in mid-2017, the Alaska legislature subsequently reversed the prohibition on using transferred Tax Credit certificates for prior year’s obligations, to date transferred Tax Credit certificates cannot be used to go below the four percent floor, and the secondary market remains inactive.

One recent development may accelerate payment of the account receivable. The Governor of Alaska has introduced legislation to allow Alaska to issue bonds to pay-off at a discount its approximately $1.2 billion liability for Tax Credits. There can be no assurance, however, that this alternative will provide a viable means to monetize our Tax Credit certificates.

We continue to explore all the options described above to monetize the Tax Credit certificates. We continue to believe that selling the certificates at a discount to producers that are able to apply the certificates to reduce their own Alaskan tax liabilities should yet again become a viable monetization option. We have a contract with a producer that provides that the producer will purchase our Tax Credit certificates to the extent that it can use them to satisfy its tax liabilities. In December 2017 the active Alaskan producers agreed to a $786 million settlement regarding tariffs relating to the Trans Alaskan pipeline with FERC, which FERC approved in March 2018 that will result in significantly increased production taxes being owed by the producers to the State of Alaska. Those taxes could be satisfied by purchase of Tax Credit certificates, at a discount to the face value of the Tax Credit certificate. Alternatively we could sell our Tax Credit certificates to other third parties, at a discount. We also believe that rising oil prices may increase the market for the Tax Credit certificates, but there can be no assurance that prices will increase sufficient to improve the market or when it might occur.
 
We have other possible ways to receive payments on our account receivable that do not involve monetization of the Tax Credits. We continue to assist the customer in actively marketing and licensing of the seismic data we collected on behalf of our customer. Licensing revenues received must be paid to us in satisfaction of our account receivable.   In addition, subject to any licenses granted, the customer has the right to sell the data and apply the proceeds to our receivable.  We believe that the receipt of these

33


licensing revenues and sales proceeds may be sufficient to cover the difference between the outstanding account receivable and the cash we are able to generate by monetization of the Tax Credits, but there can be no assurance that it will occur or when any such payments will be received.

A risk exists that any monetization of the Tax Credit certificates will require a selling at a discount, and that the discount may be substantial, resulting in proceeds insufficient to fully repay the customer’s outstanding account receivable. Should this result, and we do not receive additional payments from our customer from either licensing or selling the seismic data, we may be required to record an impairment to the amount due from our customer. At this point, however, we do not believe that it is probable that the account receivable was impaired as of December 31, 2017, due in main part to the fact that the State of Alaska is obligated to fully fund its Tax Credit certificate liabilities regardless of the timing of such payments.

During 2016 and 2017, we explored a range of transactions to address our significant cash flow and liquidity difficulties and the longer term need to realign our capital structure with our current business. On December 19, 2017, we entered into a restructuring support agreement (the "2017 Restructuring Support Agreement") with holders (the "2017 Supporting Holders") that beneficially owned in excess of 85% in principal amount of our Second Lien Notes to provide additional liquidity and realign our capital structure to better support operations during the prolonged industry downturn. On June 13, 2016, we entered into a comprehensive restructuring support agreement (the “2016 Restructuring Support Agreement”) with holders (the “2016 Supporting Holders”) of approximately 66% of the par value of the 10% Senior Secured Notes due 2019 (the "Senior Secured Notes") to address its cash flow and liquidity difficulties and uncertainty regarding the State of Alaska tax credit program, and continued downturn in the oil and natural gas exploration sector. The 2016 Supporting Holders agreed to a comprehensive restructuring of our balance sheet, which included the funding of up to $30 million in new capital (the “2016 Restructuring”). The 2017 Restructuring and the 2016 Restructuring are further discussed in Note 2.

As a part of the 2017 Restructuring, we completed a debt for equity exchange primarily involving holders of our Second Lien Notes, which exchanged 91.8% of the outstanding aggregate principal amount of the Second Lien Notes for common stock, preferred stock and warrants. As a part of the 2016 Restructuring, we completed a debt for equity exchange involving our Senior Secured Notes, which deferred the cash requirement for the July 2016 interest payment and at our election allowed for the payment of interest in kind for a period of up to 12 months on the exchanged debt, with the deferred and in-kind interest payments ultimately due at the maturity of the Second Lien Notes. As a result of the completion of the Restructurings, at March 8, 2018, our total outstanding indebtedness was $57,817 consisting of Senior Secured Notes of $1,865, Second Lien Notes of $6,952, borrowings under our Senior Loan Facility of $29,000 and borrowings under our Credit Facility of $20,000. The 2016 and 2017 Restructurings are further discussed in Note 8.

While the Restructurings have mitigated the acuteness of our liquidity and cash flow issues, there can be no assurance that they will solve our need to monetize our Tax Credit certificates.

Capital Expenditures.  Cash used in investing activities during 2017 was $760, compared to $2,864 during 2016, a decrease in cash used of $2,104. The decrease in purchase of property and equipment primarily resulted from lower capital expenditures during 2017 compared to 2016, primarily due to the prolonged downturn in the oil and gas market. Our 2017 capital expenditures primarily relate to remaining cash payments for the 2016 purchase of a set of vibrators as well as the purchase of additional camp equipment and vibrators in the first quarter of 2017. The proceeds from sale of assets represents cash received from the sale of ocean bottom nodal equipment in the fourth quarter of 2016. Based on current information, we expect our total capital expenditures for 2018 to be under $5.0 million. This amount will permit us to maintain the operational capability of our current fleet of equipment so that we can execute ongoing projects without delay or increased costs. This amount, however, will not allow us to purchase any new technology or make any significant upgrades to existing capital assets. Capital expenditures in 2016 totaled $3,352, which primarily consisted of a set of vibrators purchased for our North America operations.
  
Financing. Cash used in financing activities during 2017 was $3,274, compared to cash provided by financing activities of $21,842 during 2016, an increase in cash provided by financing activities of $25,116. Cash used in financing activities in 2017 was primarily related to our net repayments of our Prior Credit Agreement in 2017, distributions to our noncontrolling interest and financing costs paid for the 2017 Restructuring. Cash provided by financing activities in 2016 primarily resulted from borrowings under our Senior Loan Facility, partially offset by payment of loan issuance costs related to the 2016 Restructuring, repayment of our Prior Credit Agreement, and the distribution payment to our noncontrolling interest. As of December 31, 2017, our total outstanding indebtedness was $121,293, consisting of Senior Secured Notes of $1,847, Second Lien Notes of $85,050, borrowings under our Senior Loan Facility of $29,995, and borrowings under our Credit Facility of $4,401.

Senior Secured Notes. On July 2, 2014, we entered into an indenture ("Indenture") under which we issued $150,000 of senior secured notes due July 15, 2019, in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions pursuant to Regulation S under the Securities Act. On June 19, 2015, all

34


outstanding senior secured notes were exchanged for an equal amount of new Senior Secured Notes, which are substantially identical in terms to the original senior secured notes except that the Senior Secured Notes are registered under the Securities Act of 1933, as amended. The Senior Secured Notes bear interest at the annual rate of 10% payable semi-annually in arrears on January 15 and July 15 of each year, commencing on January 15, 2015. For a complete discussion of the terms and security for the Senior Secured Notes, see Note 8.

The Indenture relating to the Senior Secured Notes contains covenants which include limitations on our ability to:

transfer or sell assets;
pay dividends, redeem subordinated indebtedness or make other restricted payments;
incur or guarantee additional indebtedness or, with respect to our restricted subsidiaries, issue preferred stock;
create or incur liens;
incur dividend or other payment restrictions affecting our restricted subsidiaries;
consummate a merger, consolidation or sale of all or substantially all of our or our subsidiaries’ assets;
enter into transactions with affiliates;
engage in business other than our current business and reasonably related extensions thereof; and
take or omit to take any actions that would adversely affect or impair in any material respect the collateral securing the Senior Secured Notes.
We were in compliance with the Indenture covenants for the Senior Secured Notes as of December 31, 2017.

Exchange of Senior Secured Notes for Second Lien Notes. As discussed in Note 2, we commenced an offer on June 24, 2016 to exchange each $1 of the Senior Secured Notes for (i) $0.50 of newly issued 10% Senior Secured Second Lien Notes due 2019 ("Second Lien Notes") and (ii) 46.41 shares of the newly issued common stock (giving effect to a 135-for-1 reverse stock split that was effected in connection with closing of the exchange offer). The exchange offer closed on July 27, 2016 (the "2016 Closing Date"). On the 2016 Closing Date, a total of $138,128 face value of the Senior Secured Notes were exchanged for (i) $76,523 Second Lien Notes, including $7,459 Second Lien Notes representing accrued and unpaid interest and (ii) 6,410,502 shares of our common stock.

The exchange was accounted for as a modification in the year ended December 31, 2016. The Second Lien Notes were recorded at the net carrying value of the Senior Secured Notes exchanged of $134,522, less the fair value of our common stock issued to participating noteholders of $65,003, plus the accrued and unpaid interest of $7,459 included in the exchange. The resulting $455 excess of carrying value over face value of the Second Lien Notes is being amortized over the term of the Second Lien Notes. The fair value of the common stock was determined using the probability-weighted expected return method based on a combination of the income and market approaches and a mergers and acquisition scenario. Costs incurred by the participating noteholders during the exchange of $345 were recognized as debt discount and are being amortized over the term of the Second Lien Notes.

In connection with the exchange offer, we also completed a consent solicitation to make certain proposed limited amendments to the terms of the indenture for the Senior Secured Notes, the related security documents and the existing intercreditor agreement to permit the Restructuring as discussed in Note 7. The Second Lien Notes terms are substantially similar to the Senior Secured Notes with the following modifications:
 
The Second Lien Notes have a maturity date of September 24, 2019, provided that, if any of the Senior Secured Notes remain outstanding as of March 31, 2019, the maturity date of the Second Lien Notes will become April 14, 2019 upon the vote of the holders of a majority of the then-outstanding Second Lien Notes.

The liens securing the Second Lien Notes are junior to the liens securing the Senior Loan Facility and senior to the liens securing the Senior Secured Notes after the Closing Date.

In addition to the exchange consideration, each participating holder received accrued and unpaid interest on its tendered Senior Secured Notes that were accepted for exchange from their last interest payment date of January 15, 2016 to, but not including, the settlement date, which was paid in the form of Second Lien Notes with a principal amount equal to the amount of such accrued and unpaid interest totaling $7,459.

35



Interest on the Second Lien Notes is payable quarterly. We had the election to pay interest on the Second Lien Notes in kind with additional Second Lien Notes for the first twelve months of interest payment dates, provided that, if we made this election, the interest on the Second Lien Notes for such in kind payments will accrue at a per annum rate 1% percent higher than the cash interest rate of 10%. We elected to pay interest in the year ended December 31, 2017 and 2016 of $4,848 and $3,619, respectively, in kind, which was capitalized within the Second Lien Notes balance.
 
The Second Lien Notes have a special redemption right at par of up to $35 million of the issuance to be paid out of the proceeds of the Alaska Tax Credit certificates and is conditioned upon payment in full of the credit facility and the senior loan facility.

The Second Lien Notes include a make-whole provision requiring that if the Second Lien Notes are accelerated or otherwise become due and payable prior to their stated maturity due to an Event of Default (including but not limited to our bankruptcy or liquidation (including the acceleration of claims by operation of law)), then the applicable premium payable with respect to an optional redemption will also be immediately due and payable, along with the principal of, accrued and unpaid interest on, the Second Lien Notes and constitutes part of the obligations in respect thereof as if such acceleration were an optional redemption of the Second Lien Notes, in view of the impracticability and extreme difficulty of ascertaining actual damages and by mutual agreement of the parties as to a reasonable calculation of each holder’s lost profits as a result thereof.

Exchange of Senior Secured Notes and Second Lien Notes for Equity. As discussed in Note 2, in exchange for $78,037 in aggregate principal amount of Second Lien Notes, plus accrued and unpaid interest from and including January 15, 2018 thereon, representing approximately 91.8% of the outstanding aggregate principal amount of the Second Lien Notes, validly tendered and accepted for exchange in the 2017 Exchange Offer, and $7 in aggregate principal amount of Senior Secured Notes, plus accrued and unpaid interest from and including January 15, 2018 thereon, representing less than 1% of the outstanding aggregate principal amount of the Senior Secured Notes, validly tendered and accepted for exchange in the 2017 Exchange Offer, we issued (i) 812,321 newly issued shares of the our common stock, (ii) 31,669 newly issued shares of the our Series A perpetual convertible preferred stock, (iii) 855,195 newly issued shares of our Series B convertible preferred stock, which is mandatorily convertible, subject to certain conditions, and (iv) 8,286,061 newly issued Series C Warrant to purchase 8,286,061 shares of Common Stock.
Concurrently with the 2017 Exchange Offer, we solicited consents related to the adoption of proposed amendments to each of the indenture governing the Second Lien Notes and the Indenture governing the Senior Secured Notes, Holders of approximately 91.8% of the principal amount of the Second Lien Notes delivered their consents for us to adopt the proposed amendments to the indenture governing the Second Lien Notes, and to effect the proposed collateral release.
On January 26, 2018, we entered into a first supplemental indenture to the Indenture governing the Second Lien Notes and a first amendment to the security agreement relating to the Second Lien Notes to effect the proposed amendments and collateral release.

We may from time to time seek to retire or purchase our remaining outstanding Senior Secured Notes and Second Lien Notes through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the availability of cash and our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Facility. On September 22, 2017, SAExploration, Inc. (“Borrower”), us and our other domestic subsidiaries entered into the First Amended and Restated Credit and Security Agreement (the "Credit Agreement") with the lenders from time to time party thereto and Cantor Fitzgerald Securities, as agent (the "Agent"). The Credit Agreement amends and restates the Credit and Security Agreement dated as of November 6, 2014 and as amended on June 29, 2016 (the "Prior Credit Agreement") by and among the Borrower, the Guarantors, and Wells Fargo Bank, National Association as lender (the "Original Lender"). Immediately prior to entering into the Credit Agreement, the Original Lender sold its interest in the Prior Credit Agreement upon entering into the Loan Assignment, Assumption and Indemnity Agreement (the "Assignment Agreement") with the Agent who subsequently assigned those rights and obligations to one of our Supporting Holders (the "Assignee"). Two additional holders elected to join the Credit Agreement (together with the Assignee, the "Lenders"), including one holder as further described in Note 6.

On December 22, 2017, the parties entered into an amendment to the Credit Agreement ("First Amendment") which among other things: (1) increased the maximum borrowings to $20,000 from $16,000 and (2) added two additional lenders. The First Amendment was accounted for as a modification in the year ended December 31, 2017.

The Credit Agreement provides for up to $20,000 in borrowings secured primarily by the Borrower's North American assets, mainly accounts receivable and equipment subject to certain exclusions (the "Credit Facility"). The proceeds of the Credit Facility

36


will primarily be used to fund the Borrower's working capital needs for its operations and for general corporate purposes. As of December 31, 2017, borrowings outstanding under the Credit Facility were:

 
December 31, 2017
 
 
Principal outstanding
$
5,000

Less: unamortized deferred loan issuance costs
(599
)
Total Credit Facility outstanding
$
4,401


Additional borrowings under the Credit Facility are subject to Lenders’ sole discretion and must be in minimum increments of $1,000.

In addition to the above and among other things, the Credit Agreement:
eliminated the ability to redraw borrowings once repaid and placed certain restrictions on the ability to repay borrowings;

eliminated the sub-facility for letters of credit;

provided for mandatory prepayment with any proceeds from Tax Credits that exceeded $15,000, unless waived by the Lenders; and

removed certain covenants including those to maintain a minimum EBITDA specified above and to maintain eligible equipment of a certain amount.

The Credit Agreement was accounted for as a modification during the year ended December 31, 2017. In connection with the Credit Agreement, deferred loan issuance costs totaling $782 were recorded during the year ended December 31, 2017 consisting of $400 of fees, payable to the Lenders, and $382 of legal and investment banking costs.
Borrowings made under the Credit Facility bear interest at a rate of 10.25% per annum for the period from September 22, 2017 through and including March 22, 2018, 10.75% per annum for the period from March 23, 2018 through and including September 22, 2018 and 11.75% per annum for the period from September 23, 2018 and thereafter.
On February 28, 2018, we entered into an amendment to, among other things, remove the provision providing for an accelerated maturity date of September 14, 2018 under certain conditions. The maturity date of the Credit Agreement is January 2, 2020.
The Credit Agreement contains covenants including, but not limited to (i) commitments to maintain and deliver to the Lenders, as required, certain financial reports, records and other items and (ii) subject to certain exceptions under the Credit Agreement, restrictions on our ability to incur indebtedness, create or incur liens, enter into fundamental changes to corporate structure or to the nature of our business, dispose of assets, permit a change in control, acquire non-permitted investments, enter into affiliate transactions or make distributions. The Credit Agreement also contains representations, warranties, covenants and other terms and conditions, including relating to the payment of fees to the Lenders, which are customary for agreements of this type. We are in compliance with the Credit Agreement covenants as of December 31, 2017.

Prior Credit Agreement. Borrowings outstanding under the Prior Credit Agreement were $5,844 as of December 31, 2016. Borrowings made under the Prior Credit Agreement bore interest, payable monthly, at a rate of daily three months LIBOR plus 3% (4.00% at December 31, 2016). he Prior Credit Agreement had a maturity date of November 6, 2017, unless terminated earlier.

The Prior Credit Agreement also included a sub-facility for letters of credit in amounts up to the lesser of the available borrowing base or $10,000. Letters of credit were subject to Lender approval and a fee that accrued at the annual rate of 3% of the undrawn daily balance of the outstanding letters of credit, payable monthly. An unused line fee of 0.5% per annum of the daily average of the maximum Credit Facility amount reduced by outstanding borrowings and letters of credit is payable monthly. As of December 31, 2016, there were no letters of credit outstanding under the sub-facility and the sub-facility was eliminated in the Credit Agreement.
 
Senior Loan Facility. On June 29, 2016, we, as borrower, and each of our domestic subsidiaries, as guarantors (the “Guarantors”), entered into the Senior Loan Facility with the Supporting Holders of the Senior Secured Notes. In addition to the Supporting Holders, one additional holder of the senior secured notes subsequently elected to participate as a lender in the Senior Loan Facility based on their proportionate ownership of the Senior Secured Notes as discussed in Note 7. The Senior Loan Facility provides funding up to a maximum borrowing amount of $30,000. Under the terms of the Senior Loan Facility, $15,000 became immediately

37


available and the remaining $15,000 became available when we entered into the first amendment to the Senior Loan Facility. As of December 31, 2017 and 2016, borrowings of $29,995 were outstanding under the Senior Loan Facility.

On September 8, 2017, we entered into the Second Amendment to the Senior Loan Facility that amended and extended a majority of the Senior Loan Facility held by consenting lenders representing $29,000 of the total principal outstanding (the "Extended Loans"). The Second Amendment, among other things, for the Extended Loans:

extended the maturity date to January 2, 2020; provided that the maturity is January 2, 2019 if there are any outstanding Senior Secured Notes or Second Lien Notes at that time;

increased the interest rate from 10% per year to 10.5% beginning on September 8, 2017 to, but not including, February 8, 2018, 11.5% per year for the succeeding six-month period, and 12.5% per year thereafter until the maturity, payable monthly in cash;

provided for a mandatory prepayment with the proceeds from any Tax Credit; and

provided for a call premium with respect to certain prepayments.

On February 28, 2018, we entered into an amendment to the Senior Loan Facility to, among other things, remove the provision providing for an accelerated maturity date of January 2, 2019 under certain conditions. The maturity date of the Senior Loan Facility is January 2, 2020.

The remaining $995 of advances under the Senior Loan Facility (the "Residual Loans") remain under the original terms of the Senior Loan Facility where borrowings bear interest at a rate of 10% per year, payable monthly and the maturity date is January 2, 2018, unless terminated earlier. The Residual Loans also require mandatory prepayment from the proceeds of any Tax Credit after we have received $15,000 in proceeds from the Tax Credits. The Residual Loans were paid in full on January 2, 2018.

The Second Amendment was accounted for as a modification during the year ended December 31, 2017. In connection with the Second Amendment, deferred loan issuance costs totaling $914 were recorded in the year ended December 31, 2017. The deferred loan issuance costs recorded during these periods consisted of $600 of fees, which were paid to the lenders, and $314 of legal and investment banking costs. In connection with the initial borrowing, costs totaling $30,082 were recorded as a deferred loan issuance cost on the balance sheet in the year ended December 31, 2016. The deferred loan issuance costs recorded in 2016 included a $600 facility fee, legal and investment banking costs, and $28,425 for the fair value of 2,803,302 shares of our common stock issued to the lenders on July 27, 2016. The fair value of the common stock was determined using the probability-weighted expected return method based on a combination of the income and market approaches and a mergers and acquisition scenario.

The Senior Loan Facility is secured by substantially all of the collateral securing the obligations under (i) the Credit Agreement (ii) the Senior Secured Notes and (iii) the Second Lien Notes, including the receivable due to us discussed in Note 3. This security interest is junior to the security interest in such collateral securing the obligations under the Credit Facility and senior to the security interests in such collateral securing the obligations under the Second Lien Notes and the Senior Secured Notes.

The Senior Loan Facility contains negative covenants that restrict our and the Guarantors’ ability to incur indebtedness, create or incur liens, enter into fundamental changes to our corporate structure or to the nature of our business, dispose of assets, permit a change in control to occur, make certain prepayments, other payments and distributions, make certain investments, enter into affiliate transactions or make certain distributions, and requires that we maintain and deliver certain financial reports, projections, records and other items. The Senior Loan Facility also contains customary representations, warranties, covenants and other terms and conditions, including relating to the payment of fees to the Senior Loan Facility agent and the lenders, and customary events of default. We were in compliance with the Senior Loan Facility covenants as of December 31, 2017.

On June 29, 2016, we, the guarantors party thereto (the “Existing Notes Guarantors”) and Wilmington Savings Fund Society, FSB (successor to U.S. Bank National Association), as trustee for the Senior Secured Notes (the “Existing Trustee”), entered into a first supplemental indenture (the “Supplemental Indenture”) to the indenture governing the Senior Secured Notes (the “Existing Indenture”). The Supplemental Indenture modified the Existing Indenture to, among other things, permit the incurrence of additional secured indebtedness pursuant to the Senior Loan Facility and the issuance of the Second Lien Notes in the Exchange Offer. The Supplemental Indenture includes additional changes necessary to give effect to the 2016 Restructuring and directed the Existing Trustee, in its capacity as noteholder collateral agent for the Senior Secured Notes, to enter into the Amended and Restated Intercreditor Agreement and the amendment to the Existing Security Agreement, each as described below, on behalf of the Existing Holders. The material terms of the Existing Indenture, other than the amendments summarized above, remain substantially as set forth in the Existing Indenture.

38



On June 29, 2016, Wells Fargo, in its capacity as lender and collateral agent under the Prior Credit Agreement, Wilmington Savings Fund Society, FSB (successor to U.S. Bank National Association), in its capacity as trustee and collateral agent for the Senior Secured Notes ("Noteholder Collateral Agent"), and Delaware Trust Corporation, in its capacity as administrative agent and collateral agent for the Senior Loan Facility, amended and restated the Intercreditor Agreement, dated as of November 6, 2014, by and between Wells Fargo and Wilmington Savings Fund Society, FSB (as successor to U.S. Bank National Association) (the “Existing Intercreditor Agreement” and as amended and restated, the “Amended and Restated Intercreditor Agreement”), to govern the relationship of the Existing Holders, the holders of Second Lien Notes, and the lenders under our Credit Facility and Senior Loan Facility, with respect to the collateral and certain other matters. On September 22, 2017, the Assignment Agreement was entered into between Wells Fargo under the Prior Credit Agreement and the Agent as further described in Note 6. As a result of the Assignment Agreement, the Agent has succeeded Wells Fargo in its capacity as administrative agent and collateral agent for the Credit Facility under the Amended and Restated Intercreditor Agreement. The Amended and Restated Intercreditor Agreement, among other things, modifies the terms of the Existing Intercreditor Agreement to (i) establish the relative priorities, rights, obligations and remedies with respect to the collateral among the Existing Holders, the holders of the Second Lien Notes, the lenders under the Credit Facility, the lenders under the Senior Loan Facility, the holders of future debt that is permitted to share the security interests currently held by them and the collateral agents of the foregoing (collectively, the “Secured Parties”); and (ii) modify the terms of the Existing Intercreditor Agreement to permit the holders of obligations under the Senior Loan Facility and the Second Lien Notes to share the security interests currently held by the Existing Holders and Wells Fargo as the lender under the Credit Facility as follows:

the obligations under the Credit Facility are secured by all of the existing collateral on a senior first lien priority basis;
the obligations under the Senior Loan Facility are secured by all of the existing collateral on a junior first lien priority basis;
the obligations under the Second Lien Notes are secured by substantially all of the existing collateral on a second lien priority basis; and
the obligations under the Senior Secured Notes are secured by substantially all of the existing collateral on a third lien priority basis.

In addition, the Amended and Restated Intercreditor Agreement provides that, following a triggering event, as among the Secured Parties, the Senior Representative (defined below) will have the right (subject to a purchase option by the other Secured Parties) to, or the right to direct any other collateral agent to, adjust or settle insurance policies or claims in the event of any loss thereunder relating to insurance proceeds with respect to collateral, to approve any award granted in any condemnation or similar proceeding affecting such insurance proceeds and to enforce rights, exercise remedies and discretionary rights and powers with respect to collateral. The Secured Parties agreed that if we or any guarantor becomes subject to a case under the U.S. Bankruptcy Code, the Secured Parties will only be permitted to object to a debtor-in-possession financing or the use of cash collateral if the Secured Parties for which the Senior Representative is the collateral agent also object. The “Senior Representative” under the Amended and Restated Intercreditor Agreement is Wells Fargo as the Credit Facility agent, until the obligations under the Credit Facility have been discharged in full, after which the Senior Loan Facility agent will be the Senior Representative; and once the Credit Facility agent and the Senior Loan Facility agent each cease to be the Senior Representative and the obligations under each of the Credit Facility and Senior Loan Facility have been discharged in full, the Senior Representative will be Wilmington Savings Fund Society, FSB, as the New Noteholder Collateral Agent. The material terms of the Amended and Restated Intercreditor Agreement, other than those summarized above, remain substantially as set forth in the Existing Intercreditor Agreement, except that the Noteholder Collateral Agent will no longer have a first-priority security interest in the “Noteholder Priority Collateral” (as such term is defined in the Existing Intercreditor Agreement).

On June 29, 2016, we and the Senior Secured Notes Guarantors, as pledgors, also entered into an amendment (the “Security Agreement Amendment”) to the Security Agreement, dated as of July 2, 2014 (as amended from time to time, the “Existing Security Agreement”), with Wilmington Savings Fund Society, FSB, as Noteholder Collateral Agent for the Senior Secured Notes. The Security Agreement Amendment introduced conforming changes to reflect the provisions incorporated into the Amended and Restated Intercreditor Agreement.


39


Use of Adjusted EBITDA and Adjusted Gross Profit (Non-GAAP measures) as Performance Measures
 
Adjusted EBITDA

We use an adjusted form of EBITDA to measure period over period performance, which is a non-GAAP measurement. Adjusted EBITDA is defined as net loss plus depreciation and amortization, plus interest expense, plus income taxes, plus share-based compensation, plus loss (gain) on disposal of property and equipment, plus costs incurred on debt restructuring, plus foreign exchange loss (gain) and plus nonrecurring one-time expenses. Our management uses Adjusted EBITDA as a supplemental financial measure to assess:
  
the financial performance of our assets without regard to financing methods, capital structures, taxes, historical cost basis or nonrecurring expenses;
our liquidity and operating performance over time in relation to other companies that own similar assets and calculate Adjusted EBITDA in a similar manner; and
the ability of our assets to generate cash sufficient to pay potential interest cost.
We consider Adjusted EBITDA as presented below to be the primary measure of period-over-period changes in our operational cash flow performance. 

The computation of our Adjusted EBITDA (a non-GAAP measure) from net loss, the most directly comparable GAAP financial measure, is provided in the table below (in thousands):
 
Years Ended December 31,
 
2017
 
2016
Net loss
$
(38,784
)
 
$
(22,009
)
Depreciation and amortization (1)
12,099

 
16,910

Interest expense, net
29,363

 
23,697

Provision for income taxes
4,313

 
6,056

Share-based compensation (2)
1,925

 
1,383

Loss (gain) on disposal of property and equipment, net (3)
(101
)
 
4,542

Costs incurred on debt restructuring (4)

 
5,439

Foreign exchange loss (gain), net (5)
1,308

 
(1,977
)
Nonrecurring expenses (6)(7)
832

 
2,092

Adjusted EBITDA
$
10,955

 
$
36,133

(1)Depreciation and amortization expense was charged to the statements of operations as follows:
 
Years Ended December 31,
 
2017
 
2016
Cost of services
$
11,725

  
$
16,410

Selling, general and administrative expenses
374

 
500

Total depreciation and amortization expense
$
12,099

  
$
16,910


(2)
Share-based compensation primarily relates to the non-cash value of stock options and restricted stock awards granted to our employees and directors.
(3) Loss (gain) on disposal of property and equipment, net is primarily the impact of sale of equipment.
(4) Costs were incurred during the Restructurings.
(5)
Foreign exchange (gain) loss, net includes the effect of both realized and unrealized foreign exchange transactions.
(6)
Nonrecurring expenses in 2017 primarily consist of severance payments of $263 incurred in our Peru and Alaska locations, legal and claim costs related to employees in our Alaska and Bolivia locations, and various non-operating expenses incurred at our corporate location.
(7)
Nonrecurring expenses in 2016 primarily consist of severance payments of $928 incurred in our Peru, Colombia, Canada, Alaska and corporate locations payments related to tax services provided in connection with our Restructurings, and various non-operating expenses incurred at the corporate and Peru locations.

Adjusted Gross Profit

40



We use an adjusted form of gross profit to measure period over period performance, which is not derived in accordance with GAAP. Adjusted Gross Profit is defined as gross profit plus depreciation and amortization expense related to the cost of services. Our management uses Adjusted Gross Profit as a substantial financial measure to assess the cost management and performance of our projects. Within the seismic data services industry, companies present gross profit both with and without depreciation and amortization expense on equipment used in operations, and therefore we also use this measure to assess our performance over time in relation to other companies that own similar assets and calculate gross profit in the same manner.
The computation of our Adjusted Gross Profit (a non-GAAP measure) from gross profit, the most directly comparable GAAP financial measure, is provided in the table below (in thousands):   
 
Years Ended December 31,
 
2017
 
% of Revenue
 
2016
 
% of Revenue
 
Increase (Decrease)
 
Percentage Change
Gross profit as presented
$
22,068

 
17.3
%
 
$
45,036

 
21.9
%
 
$
(22,968
)
 
(51.0
)%
Depreciation and amortization expense included in cost of services
11,725

 
9.3
%
 
16,410

 
8.0
%
 
(4,685
)
 
(28.5
)%
Gross profit excluding depreciation and amortization expense included in cost of services
$
33,793

 
26.6
%
 
$
61,446

 
29.9
%
 
$
(27,653
)
 
(45.0
)%
(1) Depreciation and amortization expense included in cost of services includes depreciation and amortization on equipment used in operations.

The terms EBITDA, adjusted EBITDA and Adjusted Gross Profit are not defined under GAAP, and we acknowledge that these are not measures of operating income, operating performance or liquidity presented in accordance with GAAP. When assessing our operating performance or liquidity, investors and others should not consider this data in isolation or as a substitute for net income, gross profit, cash flow from operating activities or other cash flow data calculated in accordance with GAAP. In addition, our calculation of Adjusted EBITDA and Adjusted Gross Profit may not be comparable to EBITDA or Adjusted Gross Profit or similarly titled measures utilized by other companies since such other companies may not calculate EBITDA or Adjusted Gross Profit in the same manner. Further, the results presented by Adjusted EBITDA and Adjusted Gross Profit cannot be achieved without incurring the costs that the measures exclude.

Critical Accounting Policies
 
Our financial statements have been prepared on the accrual basis of accounting in accordance with GAAP. Preparation of financial statements in conformity with GAAP requires certain assumptions and estimates to be made that affect the reported amounts of assets and liabilities at the financial statement date and the reported amounts of revenues and expenses during the reporting periods covered by the financial statements. Because of the use of assumptions and estimates inherent in the reporting process, actual results could differ from those estimates.
Revenue Recognition
Our services are provided under master service agreements that set forth our obligations and the obligations of our customers. A supplemental agreement is entered into for each data acquisition project which sets forth the terms of the specific project including the right of either party to cancel on short notice. Customer contracts for services vary in terms and conditions. Contracts are either “turnkey” (fixed price) agreements that provide for a fixed fee per unit of measure, or “term” (variable price) agreements that provide for a fixed hourly, daily or monthly fee during the term of the project. Under turnkey agreements, we recognize revenue based upon output measures as work is performed. This method requires revenue recognition to be based upon quantifiable measures of progress, such as square or linear kilometers surveyed or each unit of data recorded. Expenses associated with each unit of measure are immediately recognized. If it is determined that a contract will have a loss, the entire amount of the loss associated with the contract is immediately recognized. Revenue under a “term” contract is billed as the applicable rate is earned under the terms of the agreement. Under contracts that require the customer to pay separately for the mobilization of equipment, we recognize such mobilization fees as revenue during the performance of the seismic data acquisition, using the same output measures as for the seismic work. To the extent costs have been incurred under service contracts for which the revenue has not yet been earned, those costs are deferred on the balance sheet within deferred costs on contracts until the revenue is earned, at which point the costs are recognized as cost of services over the life of the contract. If we determine that the costs are not recoverable, the costs are expensed.

41


We invoice customers for certain out-of-pocket expenses under the terms of the contracts. Amounts billed to customers are recorded in revenue at the gross amount including out-of-pocket expenses. We also utilize subcontractors to perform certain services to facilitate the completion of customer contracts. Customers are billed for the cost of these subcontractors plus an administrative fee. We record amounts billed to our customers related to subcontractors at the gross amount and record the related cost of subcontractors as cost of services. Sales taxes collected from customers and remitted to government authorities are accounted for on a net basis and are excluded from revenues in the consolidated statements of operations.

Deferred Revenue

Deferred revenue primarily represents amounts billed or payments received for services in advance of the services to be rendered over a future period or advance payments from customers related to equipment leasing.

Multiple-Element Arrangements

We evaluate each contract to determine if the contract is a multiple-element arrangement requiring different accounting treatments for varying components of the contract. If a contract is deemed to have separate units of accounting, arrangement consideration is allocated based on each unit of accounting's relative selling price and the applicable revenue recognition criteria are considered separately for each of the separate units of accounting. We account for each contract element when the applicable criteria for revenue recognition have been met. We use our best estimate of selling price when allocating multiple-element arrangement consideration.

Allowance for Doubtful Accounts
We maintain an allowance for doubtful accounts for estimated losses in our accounts receivable portfolio. We utilize the specific identification method for establishing and maintaining the allowance for doubtful accounts. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. While the collectability of outstanding customer invoices is continually assessed, the cyclical nature of our industry may affect our customers’ operating performance and cash flows, impacting our ability to collect on the invoices. Some of our customers are located in certain international areas that are inherently subject to economic, political and civil risks, which may also impact our ability to collect receivables.
Property and Equipment
 
Our property and equipment is capitalized at historical cost and depreciated over the estimated useful life of the asset. The estimation of useful life is based on circumstances that exist in the seismic industry and information available at the time of the asset purchase. Changes in technology have a significant impact on these estimates. As circumstances change and new information becomes available, these estimates could change. Seismic equipment is typically depreciated over three to ten years.
Depreciation is computed using the straight-line method. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is reflected in the results of operations for such period.
Leases as Lessee

We lease certain equipment and vehicles under lease agreements. Each lease is evaluated to determine its appropriate classification as an operating or capital lease for financial reporting purposes. Any lease that does not meet the criteria for a capital lease is accounted for as an operating lease. Minimum rent payments under operating leases are recognized on a straight-line basis over the term of the lease including any periods of free rent. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or the fair market value of the related assets. Assets under capital leases are amortized using the straight-line method over the initial lease term. Amortization of assets under capital leases is included in depreciation expense.

Long-Lived Assets

Long-lived assets, such as property and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, we first compare undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment loss is recognized to the extent that the carrying

42


value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary.

Currency Translation

The majority of our operations are conducted outside the United States in countries with stable currencies. Many contracts and local expenses are paid in local currencies and not in U.S. Dollars (“USD”). Our results of operations and cash flows could be impacted by changes in foreign currency exchange rates. We do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments for speculative purposes or to mitigate the currency exchange rate risk.

Our reporting currency is in USD. For foreign subsidiaries and branches using the local currency as their functional currency, assets and liabilities are translated at exchange rates in effect at the balance sheet dates. Revenues and expenses of these foreign subsidiaries are translated at average exchange rates for the period. Equity is translated at historical rates, and the resulting cumulative foreign currency translation adjustments resulting from this process are included as a component of accumulated other comprehensive income (loss), net of income taxes. Therefore, the USD value of these items in the financial statements fluctuates from period to period, depending on the value of the USD against these functional currencies. Exchange gains and losses arising from transactions denominated in a currency other than the functional currency of the entity involved are included in the consolidated statements of operations as foreign exchange gain (loss), net. For the foreign subsidiaries and branches using USD as their functional currency, any local currency operations are re-measured to USD. The re-measurement of these operations is included in the consolidated statements of operations as foreign exchange gain (loss).

Income Taxes

Income taxes are accounted for under the asset and liability method.  Under the asset and liability method, deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis.  This method also requires the recognition of future tax benefits for net operating loss (“NOL”) carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The deferred tax asset is reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our methodology for recording income taxes requires judgment regarding assumptions and the use of estimates, including the valuation of deferred tax assets, which can create a variance between actual results and estimates and could have a material impact on our provision or benefit for income taxes. In certain foreign jurisdictions, the local income tax rate may exceed the U.S. or Canadian statutory rates, and in many of those cases we receive a foreign tax credit for U.S. or Canadian purposes. In other foreign jurisdictions, the local income tax rate may be less than the U.S. or Canadian statutory rates. In other foreign jurisdictions we may be subject to a tax on revenues when the amount of tax liability would exceed that computed on our net income before tax in the jurisdiction, and in such cases, the tax is treated as an income tax for accounting purposes. Uncertain tax positions and the related interest and penalties are provided for based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities.

We have historically and continue to assert that foreign earnings are permanently reinvested. While we have not currently changed the assertion with respect to foreign earnings compared to prior years, we are currently evaluating the impact of U.S. Tax Reform on the global structure and any associated impacts it may have on our assertion on a go forward basis and as such have not included a provisional estimate of the impact.

The U.S. Tax Reform Act includes two new U.S. tax base erosion provisions, the GILTI provisions and the BEAT provisions. The GILTI provisions require us to include in our U.S. income tax return foreign subsidiary earnings in excess of an allowable return on the foreign subsidiary’s tangible assets. We have elected to account for GILTI tax in the period in which it is incurred, and therefore have not provided any deferred tax impacts of GILTI in our consolidated financial statements for year ended December 31, 2017. The BEAT provision in the Tax Reform Act eliminates the deduction of certain base-erosion payments made to related foreign corporations, and impose a minimum tax if greater than regular tax. Starting January 1, 2018, we will account for BEAT in the period in which it is incurred to the extent we are subject to it.

Goodwill

Goodwill represents the excess of purchase price over the fair value of the net assets acquired in the 2011 Datum Exploration Ltd. acquisition. All of our goodwill resides in the Canadian operations reporting unit ("Reporting Unit").

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We are required to evaluate the carrying value of its goodwill at least annually for impairment, or more frequently if facts and circumstances indicate that it is more likely than not impairment has occurred. We first perform a qualitative assessment by evaluating relevant events or circumstances to determine whether it is more likely than not that the fair value of the Reporting Unit exceeds its carrying amount. If we are unable to conclude qualitatively that it is more likely than not that the Reporting Unit’s fair value exceeds its carrying value, we will then apply a two-step quantitative assessment.

First, the fair value of the Reporting Unit is compared to its carrying value. If the fair value exceeds the carrying value, goodwill is not impaired and no further testing is performed. The second step is performed if the carrying value exceeds the fair value. The implied fair value of the Reporting Unit’s goodwill must be determined and compared to the carrying value of the goodwill. If the carrying value of the Reporting Unit’s goodwill exceeds its implied fair value, an impairment loss equal to the difference will be recorded.

In determining the fair value of the Reporting Unit, we rely on the Income Approach and the Market Approach. Under the Income Approach, the fair value of a business unit is based on the discounted cash flows it can be expected to generate over its remaining life. The estimated cash flows are converted to their present value equivalent using an appropriate rate of return. Under the Market Approach, the fair value of the business is based on the Guideline Public Company (“GPC”) methodology using guideline public companies whose stocks are actively traded that were considered similar to ours as of the valuation date. Valuation multiples for the GPCs were determined as of the valuation date and were applied to the Reporting Unit's operating results to arrive at an estimate of value.

Share-Based Compensation

We record the grant date fair value of share-based compensation arrangements as compensation cost using a straight-line method over the requisite service period for each separately vesting tranche of an award. The amount of share-based compensation cost recognized during a period is based on the value of the awards that are ultimately expected to vest. Forfeitures are recognized as they occur except in certain circumstances where they are required to be estimated.

Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and remediation can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Comprehensive Income

Comprehensive income includes net income (loss) as currently reported and considers the effect of additional economic events that are not required to be recorded in determining net income (loss) but rather reported as a separate component of stockholders’ equity. We report foreign currency translation gains and losses as a component of comprehensive (loss) income. Foreign currency translation gains and losses are not presented net of income taxes because the earnings of the foreign subsidiaries are considered permanently invested abroad and therefore not subject to income taxes or the income tax benefit of foreign currency translation losses would be offset by a valuation allowance.

Variable Interest Entities

We evaluate our joint venture and other entities in which we have a variable interest (a “VIE”), to determine if we have a controlling financial interest and are required to consolidate the entity as a result. The reporting entity with a controlling financial interest in the VIE will have both of the following characteristics: (i) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb the losses of the VIE that could potentially be significant to the VIE or the right to receive benefit from the VIE that could potentially be significant to the VIE.

Fair Value Measurements

We have certain assets and liabilities that are required to be measured and disclosed at fair value in accordance with GAAP. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in the principal or most advantageous market in an orderly transaction between market participants on the measurement date. When an asset or liability is required to be measured at fair value, an entity is required to maximize the use of observable inputs and minimize the use of unobservable inputs using a fair value hierarchy as follows:


44


Level 1: Observable inputs such as quoted prices for identical assets or liabilities in active markets.

Level 2: Observable inputs other than quoted prices that are directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets; quoted prices for similar or identical assets or liabilities in markets that are not active; and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

Level 3: Unobservable inputs that reflect the reporting entity’s own assumptions. Measurement is based on prices or valuation models requiring inputs that are both significant to the fair value measurement and supported by little or no market activity.

Our financial instruments include cash and cash equivalents, restricted cash, accounts receivable, other current assets, accounts payable, accrued liabilities, borrowings under the credit facility and borrowings under the senior loan facility. Due to their short-term maturities, the carrying amounts of these financial instruments approximate fair value at the respective balance sheet dates. Our financial instruments also include various issuances of notes payable. There were no financial instruments measured at fair value on a recurring basis at December 31, 2017 and 2016.

Our non-financial assets include goodwill, property and equipment, and other intangible assets, which are classified as Level 3 assets. These assets are measured at fair value on a nonrecurring basis as part of our impairment assessments and as circumstances require.

Reportable Segment

The chief operating decision maker regularly reviews financial data by country to assess performance and allocate resources, resulting in the conclusion that each country in which it operates represents a reporting unit. To determine our reportable segments, we evaluated whether and to what extent the reporting units should be aggregated. The evaluation included consideration of each reporting unit's services, types of customers, methods used to provide our services, and regulatory environment. We determined that our reporting units sold similar types of seismic data contract services to similar types of major non-U.S. and government owned/controlled oil and gas customers operating in a global market. We concluded that our seismic data contract services operations comprise one single reportable segment.

Off-Balance Sheet Arrangements
 
We did not have any off-balance sheet arrangements as of December 31, 2017 or 2016.
 
Effect of Inflation
 
We do not believe that inflation has had a material effect on our business, results of operations, or financial condition during the past two fiscal years.

Recently Issued Accounting Pronouncements
 
For a detail of recently issued accounting standards, see Note 4 to the accompanying Consolidated Financial Statements.

ITEM 8. Financial Statements and Supplementary Data.
 
The information required by this item appears beginning on page FS-1 hereof and is incorporated herein by reference.

ITEM 9A. Controls and Procedures.

Management’s Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive and principal financial officers, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of December 31, 2017, our disclosure controls and procedures were effective, in all material respects, with regard to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms for information required to be disclosed by us in the reports that we file or submit under the Exchange Act. Our disclosure controls and procedures include controls and procedures designed to ensure that information

45


required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management's Annual Report on Internal Control over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting was designed by management, under the supervision of the Chief Executive Officer and Chief Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America, and includes those policies and procedures that:

(i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
(ii)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
(iii)
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013).

Based on our evaluation under the criteria in Internal Control-Integrated Framework (2013), management has concluded that we maintained effective internal control over financial reporting as of December 31, 2017.

Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance.
 
The information required by this item is incorporated by reference to our definitive Proxy Statement to be delivered to stockholders in connection with our 2018 Annual Meeting of Stockholders.

ITEM 11. Executive Compensation.
 
The information required by this item is incorporated by reference to our definitive Proxy Statement to be delivered to stockholders in connection with our 2018 Annual Meeting of Stockholders.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
The information required by this item is incorporated by reference to our definitive Proxy Statement to be delivered to stockholders in connection with our 2018 Annual Meeting of Stockholders.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence.
 
The information required by this item is incorporated by reference to our definitive Proxy Statement to be delivered to stockholders in connection with our 2018 Annual Meeting of Stockholders.


46


ITEM 14. Principal Accountant Fees and Services.
 
The information required by this item is incorporated by reference to our definitive Proxy Statement to be delivered to stockholders in connection with our 2018 Annual Meeting of Stockholders.

PART IV

ITEM 15. Exhibits and Financial Statement Schedules.
 
(a) The following documents are filed as part of this report:
 
(1) Financial Statements.
 
The following consolidated financial statements of the Company appear beginning on page FS-1 and are incorporated by reference into Part II, Item 8:
    
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2017 and 2016
Consolidated Statements of Operations for the Years Ended December 31, 2017 and 2016
Consolidated Statements of Comprehensive Loss for the Years Ended December 31, 2017 and 2016
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Years Ended December 31, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017 and 2016
Notes to Consolidated Financial Statements
 
(2) Financial Statement Schedules.
 
All schedules are omitted because they are either not applicable or the required information is shown in the financial statements or notes thereto.
 
(3) Exhibits.
 
The information required by this item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K and is hereby incorporated by reference.


47


SIGNATURES
 
Pursuant to the requirements of the Section 13 or 15 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
SAEXPLORATION HOLDINGS, INC.
 
 
Date: March 15, 2018
By:
/s/ Brent Whiteley
 
 
Brent Whiteley
 
 
Chief Financial Officer, General Counsel and
Secretary
 
POWER OF ATTORNEY
 
The undersigned directors and officers of SAExploration Holdings, Inc. hereby constitute and appoint Jeff Hastings and Brent Whiteley, and each of them, with full power to act without the other and with full power of substitution and resubstitution, our true and lawful attorneys-in-fact with full power to execute in our name and behalf in the capacities indicated below, this annual report on Form 10-K and any and all amendments thereto and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, and hereby ratify and confirm all that such attorneys-in-fact, or any of them, or their substitutes shall lawfully do or cause to be done by virtue hereof.
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE 
 
TITLE
 
DATE
 
 
 
 
 
/s/ Jeff Hastings
 
Chief Executive Officer and Chairman of the Board
 
March 15, 2018
Jeff Hastings
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ Brian Beatty
 
Chief Operating Officer and Director
 
March 15, 2018
Brian Beatty
 
 
 
 
 
 
 
 
 
/s/ Brent Whiteley
 
Chief Financial Officer, General Counsel, and
 
March 15, 2018
Brent Whiteley
 
Secretary (Principal Financial Officer and Principal Accounting Officer)
 
 
 
 
 
 
 
/s/ L. Melvin Cooper
 
Director
 
March 15, 2018
L. Melvin Cooper
 
 
 
 
 
 
 
 
 
/s/ Gary Dalton
 
Director
 
March 15, 2018
Gary Dalton
 
 
 
 
 
 
 
 
 
/s/ Michael Faust
 
Director
 
March 15, 2018
Michael Faust
 
 
 
 
 
 
 
 
 
/s/ Alan B. Menkes
 
Director
 
March 15, 2018
Alan B. Menkes
 
 
 
 
 
 
 
 
 
/s/ Jacob Mercer
 
Director
 
March 15, 2018
Jacob Mercer
 
 
 
 


48


EXHIBIT INDEX 

Exhibit
No.
 
Description
 
Included
 
Form
 
Filing Date
 
Agreement and Plan of Reorganization dated as of December 10, 2012, by and among the Corporation, Trio Merger Sub, Inc., SAExploration Holdings, Inc. and CLCH, LLC.
 
By Reference
 
8-K
 
December 11, 2012
 
 
 
 
 
 
 
 
 
 
First Amendment to Agreement and Plan of Reorganization dated as of May 23, 2013, by and among the Corporation, Trio Merger Sub, Inc., SAExploration Holdings, Inc. and CLCH, LLC.
 
By Reference
 
8-K
 
May 28, 2013
 
 
 
 
 
 
 
 
 
 
Restructuring Support Agreement dated as of June 13, 2016, among the Corporation, the members of management identified therein and the supporting holders identified therein.
 
By Reference
 
8-K
 
June 13, 2016
 
 
 
 
 
 
 
 
 
 
Restructuring Support Agreement dated as of December 19, 2017, by and among SAExploration Holdings, Inc., certain subsidiaries of SAExplorations Holdings, Inc., the members of management identified therein and the supporting holders identified therein.
 
By Reference
 
8-K
 
December 20, 2017
 
 
 
 
 
 
 
 
 
 
Third Amended and Restated Certificate of Incorporation.
 
By Reference
 
8-K/A
 
September 9, 2016
 
 
 
 
 
 
 
 
 
 
Certificate of Amendment to Third Amended and Restated Certificate of Incorporation.
 
By Reference
 
8-K
 
March 8, 2018
 
 
 
 
 
 
 
 
 
 
Second Amended and Restated By-Laws.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Amendment No. 1 to Second Amended and Restated By-Laws.
 
By Reference
 
8-K
 
March 8, 2018
 
 
 
 
 
 
 
 
 
 
Certificate of Designations of 8.0% Cumulative Perpetual Series A Preferred Stock and Form of Series A Preferred Stock Certificate.
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Certificate of Designations of Mandatorily Convertible Series B Preferred Stock and Form of Series B Preferred Stock Certificate..
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Specimen Common Stock Certificate.
 
By Reference
 
8-K
 
June 28, 2013
 
 
 
 
 
 
 
 
 
 
Indenture, dated July 2, 2014, by and among the Corporation, the guarantors named therein and U.S. Bank National Association, as trustee and noteholder collateral agent.
 
By Reference
 
8-K
 
July 9, 2014
 
 
 
 
 
 
 
 
 
 
Form of 10.000% Senior Secured Notes due 2019.
 
By Reference
 
10-Q
 
August 7, 2015
 
 
 
 
 
 
 
 
 

49


 
Notation of Guarantee executed June 19, 2015, among the Corporation, SAExploration Sub, Inc., SAExploration, Inc., SAExploration Seismic Services (US), LLC and NES, LLC.
 
By Reference
 
10-Q
 
August 7, 2015
 
 
 
 
 
 
 
 
 
 
First Supplemental Indenture, dated as of June 29, 2016, among the Corporation, the guarantors party thereto, and Wilmington Savings Fund Society, FSB, as trustee and noteholder collateral agent.
 
By Reference
 
8-K
 
July 1, 2016
 
 
 
 
 
 
 
 
 
 
Indenture, dated July 27, 2016, by and among the Corporation, the guarantors named therein and Wilmington Savings Fund Society, FSB, as trustee and noteholder collateral agent.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Form of 10.000% Senior Secured Second Lien Notes due 2019.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Notation of Guarantee executed July 27, 2016, among SAExploration Sub, Inc., SAExploration, Inc., SAExploration Seismic Services (US), LLC and NES, LLC.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
First Supplemental Indenture, dated January 26, 2018, to Indenture, dated July 27, 2016, by and among the Corporation, the guarantors named therein and Wilmington Savings Fund Society, FSB, as trustee and noteholder collateral agent.
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Warrant Agreement, dated as of July 27, 2016 between the Corporation and Continental Stock Transfer & Trust Company, as Warrant Agent.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Warrant Agreement, dated as of January 29, 2018, between the Corporation and Continental Stock Transfer & Trust Company, as Warrant Agent and the form of Series C Warrant Certificates.
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Warrant Agreement, dated as of March 8, 2018, between the Corporation and Continental Stock Transfer & Trust Company, as Warrant Agent and the form of Series D Warrant Certificates.
 
By Reference
 
8-K
 
March 8, 2018
 
 
 
 
 
 
 
 
 
 
Registration Rights Agreement dated June 24, 2013, by and between the Corporation and CLCH, LLC.
 
By Reference
 
8-K
 
June 28, 2013
 
 
 
 
 
 
 
 
 
 
Registration Rights Agreement dated July 27, 2016, between the Corporation and the holders named therein.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment dated as of August 25, 2016 to Registration Rights Agreement dated July 27, 2016, between the Corporation and the holders named therein.
 
By Reference
 
8-K
 
August 25, 2016
 
 
 
 
 
 
 
 
 

50


 
Registration Rights Agreement, dated January 29, 2018, by and among the Corporation and the holders named therein.
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Merger Consideration Escrow Agreement dated as of June 24, 2013, by and among the Corporation, CLCH, LLC and Continental Stock Transfer & Trust Company.
 
By Reference
 
8-K
 
June 28, 2013
 
 
 
 
 
 
 
 
 
 
Form of Indemnification Agreement.
 
By Reference
 
8-K
 
June 28, 2013
 
 
 
 
 
 
 
 
 
 
Security Agreement, dated July 2, 2014, by and among the Corporation, the guarantors named therein and U.S. Bank National Association, as noteholder collateral agent.
 
By Reference
 
8-K
 
July 9, 2014
 
 
 
 
 
 
 
 
 
 
Credit and Security Agreement, dated November 6, 2014, by and among SAExploration, Inc. as Borrower, the Corporation, SAExploration Sub, Inc., SAExploration Seismic Services (US), LLC, and NES, LLC as Guarantors, and Wells Fargo Bank, National Association as Lender.
 
By Reference
 
8-K
 
November 12, 2014
 
 
 
 
 
 
 
 
 
 
First Amendment to Credit and Security Agreement dated as of June 29, 2016, by and among Wells Fargo Bank, National Association, SAExploration, Inc., the Corporation, SAExploration Sub, Inc., NES, LLC, and SAExploration Seismic Services (US), LLC.
 
By Reference
 
8-K
 
July 1, 2016
 
 
 
 
 
 
 
 
 
 
First Amended and Restated Credit and Security Agreement, dated as of September 22, 2017, by and among SAExploration, Inc., as Borrower, the Guarantors from time to time party thereto, the Lenders from time to time party thereto and Cantor Fitzgerald Securities, as Agent.
 
By Reference
 
8-K
 
September 29, 2017
 
 
 
 
 
 
 
 
 
 
Amendment No. 1 to First Amended and Restated Credit and Security Agreement, dated as of December 21, 2017, by and among SAExploration, Inc., as Borrower, the Guarantors party thereto, the Lenders party thereto and Cantor Fitzgerald Securities, as Agent.
 
By Reference
 
8-K
 
December 26, 2017
 
 
 
 
 
 
 
 
 
 
Amendment No. 2 to First Amended and Restated Credit and Security Agreement, dated as of February 28, 2018, by and among SAExploration, Inc., as Borrower, the Guarantors party thereto, the Lenders party thereto and Cantor Fitzgerald Securities, as Agent.
 
By Reference
 
8-K
 
March 2, 2018
 
 
 
 
 
 
 
 
 
 
Term Loan and Security Agreement, dated as of June 29, 2016, by and among the Corporation, as borrower, the guarantors named therein, as guarantors, the lenders, from time to time party thereto, as lenders and Delaware Trust Company, as collateral agent and administrative agent.
 
By Reference
 
8-K
 
July 1, 2016
 
 
 
 
 
 
 
 
 

51


 
Amended and Restated Intercreditor Agreement, dated as of June 29, 2016, by and among Wells Fargo Bank, National Association, as lender and collateral agent, Wilmington Savings Fund Society, FSB, as trustee and collateral agent, Delaware Trust Company, as administrative agent, collateral agent and, upon execution of an additional indebtedness joinder and designation, the additional noteholder agent.
 
By Reference
 
8-K
 
July 1, 2016
 
 
 
 
 
 
 
 
 
 
Security Agreement, dated July 27, 2016, by and among the Corporation, the guarantors named therein and Wilmington Savings Fund Society, FSB, as noteholder collateral agent.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Additional Indebtedness Joinder and Designation, dated as of July 27, 2016, by and among Wells Fargo Bank, National Association, as ABL Agent, Wilmington Savings Fund Society, FSB, as Existing Noteholder Agent, Delaware Trust Company, as Term Agent, and Wilmington Savings Fund Society, FSB, as Additional Noteholder Agent.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Amendment No. 1 dated as of October 24, 2016 to Term Loan and Security Agreement, dated as of June 29, 2016.
 
By Reference
 
8-K
 
October 27, 2016
 
 
 
 
 
 
 
 
 
 
Amendment No. 2 dated as of September 8, 2017 to Term Loan and Security Agreement.
 
By Reference
 
8-K
 
September 14, 2017
 
 
 
 
 
 
 
 
 
 
Amendment No. 3 dated as of February 28, 2018 to Term Loan and Security Agreement.
 
By Reference
 
8-K
 
March 2, 2018
 
 
 
 
 
 
 
 
 
 
Amendment No. 1, dated as of January 26, 2018, to Security Agreement dated July 27, 2016, by and among the Corporation, the Guarantors named therein and Wilmington Savings Fund Society, FSB, as noteholder collateral agent.
 
By Reference
 
8-K
 
February 1, 2018
 
 
 
 
 
 
 
 
 
 
Form of Director and Officer Indemnification Agreement.
 
By Reference
 
8-K
 
August 1, 2016
 
 
 
 
 
 
 
 
 
 
Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Jeff Hastings.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Jeff Hastings.
 
By Reference (*)
 
10-Q
 
August 21, 2017
 
 
 
 
 
 
 
 
 
 
Second Amendment to Amended and Restated Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Jeff Hastings.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 

52


 
Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Brian Beatty.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Brian Beatty.
 
By Reference (*)
 
10-Q
 
August 21, 2017
 
 
 
 
 
 
 
 
 
 
Second Amendment to Amended and Restated Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Brian Beatty.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Brent Whiteley.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Brent Whiteley.
 
By Reference (*)
 
10-Q
 
August 21, 2017
 
 
 
 
 
 
 
 
 
 
Second Amendment to Amended and Restated Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Brent Whiteley.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Mike Scott.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Amended and Restated Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Mike Scott.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amended and Restated Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Darin Silvernagle.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Amended and Restated Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Darin Silvernagle.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Executive Employment Agreement, dated August 3, 2016, by and between the Corporation and Ryan Abney.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
First Amendment to Executive Employment Agreement, dated November 10, 2016, by and between the Corporation and Ryan Abney.
 
By Reference (*)
 
8-K
 
November 15, 2016
 
 
 
 
 
 
 
 
 
 
Second Amendment to Executive Employment Agreement, dated January 29, 2018, by and between the Corporation and Ryan Abney.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 

53


 
SAExploration Holdings, Inc. 2016 Long-Term Incentive Plan, Form of Notice of Stock Option Award-MIP Options and Form of Stock Option Award Agreement-MIP Options and Form of Notice of Stock Units Award-MIP Stock Units and Form of Stock Units Award Agreement-MIP Stock Units.
 
By Reference (*)
 
8-K
 
August 9, 2016
 
 
 
 
 
 
 
 
 
 
Amended and Restated 2016 Long-Term Incentive Plan.
 
By Reference (*)
 
8-K
 
May 10, 2017
 
 
 
 
 
 
 
 
 
 
2018 Long-Term Incentive Plan.
 
By Reference (*)
 
DEF14C
 
February 9, 2018
 
 
 
 
 
 
 
 
 
 
Code of Ethics.
 
By Reference
 
S-1/A
 
April 28, 2011
 
 
 
 
 
 
 
 
 
 
List of subsidiaries.
 
By Reference
 
S-4
 
April 30, 2015
 
 
 
 
 
 
 
 
 
 
Consent of Pannell Kerr Forster of Texas, P.C.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.IN
 
XBRL Instance Document.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.SCH
 
XBRL Taxonomy Extension Scheme Document.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.CAL
 
XBRL Taxonomy Calculation Linkbase Document.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Document.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.LAB
 
XBRL Taxonomy Label Linkbase Document.
 
Herewith
 
 
 
 
 
 
 
 
 
 
 
 
 
101.PRE
 
XBRL Taxonomy Presentation Linkbase Document.
 
Herewith
 
 
 
 
_____________________________________________
(*) Denotes compensation arrangement.



54


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
SAEXPLORATION HOLDINGS, INC.
 
 
 
Page
 
 
 
Consolidated Financial Statements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


FS-1


Report of Independent Registered Public Accounting Fir