TABLE OF CONTENTS

DAWSON GEOPHYSICAL COMPANY

FORM 10‑K

For the Year Ended December 31, 20162019

DISCLOSURE REGARDING FORWARD‑LOOKING STATEMENTS

Statements other than statements of historical fact included in this Form 10‑K that relate to forecasts, estimates or other expectations regarding future events, including without limitation, statements under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” regarding technological advancements and our financial position, business strategy, and plans and objectives of our management for future operations, may be deemed to be forward‑looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When used in this Form 10‑K, words such as “anticipate,” “believe,” “estimate,” “expect,” “intend” and similar expressions, as they relate to us or our management, identify forward‑looking statements. Such forward‑looking statements are based on the beliefs of our management, as well as assumptions made by and information currently available to management. Actual results could differ materially from those contemplated by the forward‑looking statements as a result of certain factors, including, but not limited to, dependence upon energy industry spending; the volatility of oil and natural gas prices; changes in economic conditions; the potential for contract delays; reductions or cancellations of service contracts; limited number of customers; credit risk related to our customers; reduced utilization; high fixed costs of operations and high capital requirements; operational disruptions; industry competition; external factors affecting the Company’s crews such as weather interruptions and inability to obtain land access rights of way; whether the Company enters into turnkey or day rate contracts; crew productivity; the availability of capital resources; and disruptions in the global economy. See “Risk Factors” for more information on these and other factors. These forward‑looking statements reflect our current views with respect to future events and are subject to these and other risks, uncertainties and assumptions relating to our operations, results of operations, growth strategies and liquidity. The cautionary statements made in this Form 10‑K should be read as applying to all related forward‑looking statements wherever they appear in this Form 10‑K. All subsequent written and oral forward‑looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this paragraph. We assume no obligation to update any such forward‑looking statements.

Part I

Item 1.  BUSINESS

General

Dawson Geophysical Company, a Texas corporation (the “Company”), is a leading provider of North AmericaAmerican onshore seismic data acquisition services with operations throughout the continental United States (“U.S.”) and Canada. We acquire and process 2‑D, 3‑D and multi‑component seismic data for our clients, ranging from major oil and gas companies to independent oil and gas operators as well as providers of multi‑client data libraries. Our principal business office is located at 508 West Wall, Suite 800, Midland, Texas 79701 (Telephone: 432‑684‑3000), and our internet address is www.dawson3d.com. We make available free of charge on our website our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, and current reports on Form 8‑K as soon as reasonably practicable after filing or furnishing such information with the Securities and Exchange Commission (“SEC”).

On February 11, 2015, the Company, which was formerly known as TGC Industries, Inc. (“Legacy TGC”), consummated a strategic business combination with Dawson Operating Company, which was formerly known as Dawson Geophysical Company (“Legacy Dawson”), pursuant to which a wholly‑owned subsidiary of Legacy TGC merged with and into Legacy Dawson, with Legacy Dawson continuing after the merger as the surviving entity and a wholly‑owned subsidiary of Legacy TGC (the “Merger”). In connection with the Merger, Legacy Dawson changed its name to “Dawson Operating Company” and Legacy TGC changed its name to “Dawson Geophysical Company.” Legacy TGC was formed in 1980. Legacy Dawson was formed in 1952.

Except as otherwise specifically noted herein, references herein to the “Company,” “we,” “us” or “our” refer to post‑combination Dawson Geophysical Company and its consolidated subsidiaries, including Legacy Dawson.

We provide our seismic data acquisition services primarily to onshore oil and natural gas exploration and development companiesproviders of multi‑client data libraries for use in the onshore drilling and production of oil and natural gas in the continental U.S. and Canada, as well as providers of multi‑client data libraries.directly to onshore oil and natural gas exploration and development companies. The main factors influencing demand for seismic data acquisition services in our industry are the level of drilling and completion activity by oil and natural gas companies and the sizessize of such companies’ exploration and development budgets, which, in turn, depend largely on current and anticipated future crude oil and natural gas prices and production levels and depletion rates of the companies’ oil and natural gas reserves.

As of December 31, 2016, we operated seven seismic crews, consisting of three crews in the U.S. and four crews in Canada, and one seismic data processing center. During the three months ended December 31, 2016, we operated a maximum of six crews in the U.S. and four in Canada. We anticipate operating four to six crews in the U.S. and Canada through the first quarter of 2017. Visibility for active crew count beyond the first quarter is limited due to uncertainty in oil prices and demand levels. Demand for our services is likely to continue to be at reduced levels in North America in response to the reduced expenditures by our clients related to the depressed crude oil prices. Our seismic crews supply seismic data primarily to companies engaged in the exploration and development of oil and natural gas on land and in land‑to‑water transition areas. Seismic acquisition services of our wholly‑owned subsidiary, Eagle Canada Seismic Services, ULC (“Eagle Canada”), are also used by the potash mining industry in Canada, and Eagle Canada has particular expertise through its heliportable capabilities. Our clients rely on seismic data to identify areas where subsurface conditions are favorable for the accumulation of existing hydrocarbons, to optimize the development and production of hydrocarbon reservoirs, to better delineate existing oil and natural gas fields, and to augment reservoir management techniques. In addition, seismic data are sometimes utilized in unconventional reservoirs to identify geo-hazards (such as subsurface faults) for drilling purposes, aid in geo-steering of a horizontal well bore and rock property identification for high grading of well locations and hydraulic fracturing. The majority of our current activity is in areas of unconventional reservoirs.

We acquire geophysical data using the latest in 3‑D seismic survey techniques. We introduce acoustic energy into the ground by using vibration equipment or dynamite detonation, depending on the surface terrain, area of operation, and subsurface requirements. The reflected energy, or echoes, are received through geophones, converted into a digital signal at a multi‑channel recording unit, and then transmitted to a central recording vehicle. Subsurface requirements dictate the number of channels necessary to perform our services. We generally use tens of thousands of recording channels in our 3-D seismic surveys. Additional recording channels enhance the resolution of the seismic survey through increased imaging analysis and provide improved operational efficiencies for our clients. With our state‑of‑the‑art seismic equipment, including computer technology and multiple channels, we acquire, on a cost effectivean efficient basis, immense volumes of seismic data that,

data to generate 3‑D geologic models that help reduce drilling risks, finding and development costs, and improve recovery rates from existing fields.

In addition to conventional 2‑D and 3‑D seismic surveys, we provide what the industry refers to as multi‑component seismic data surveys. Multi‑component surveys involve the recording of alternative seismic waves known as shear waves. Shear waves can be recorded as wave conversion of conventional energy sources (3‑C converted waves) or from horizontal vibrator energy source units (shear wave vibrators). Multi‑component data are utilized in further analysis of subsurface rock type, fabric and reservoir characterization. We own equipment required for onshore multi‑component surveys. The majority of the projects in Canada require multi‑component recording equipment. We have operated one to two multi‑component equipped crews in the U.S. routinely over the past few years. The use of multi‑component seismic data could increase in North America over the next few years if industry conditions improve and potentially require capital expenditures for additional equipment.

In recent years, we have begun providing surface‑recorded microseismic services utilizing equipment we currently own. Microseismic monitoring is used by clients who use hydraulic fracturing to extract hydrocarbon deposits to monitor their hydraulic fracturing operations. In addition, seismic data are sometimes utilized in unconventional reservoirs to identify geo-hazards (such as subsurface faults) for drilling purposes, aid in geo-steering of a horizontal well bore and rock property identification for high grading of well locations and hydraulic fracturing. The majority of our current activity is in areas of unconventional reservoirs.

We market and supplement our services in the continental U.S. from our headquarters in Midland, Texas and from additional offices in three other cities in Texas (Denison, Houston and Plano) as well as two additional states, Oklahoma (Oklahoma City) and Colorado (Denver). In addition, we market and supplement our services in Canada from our facilities in Calgary, Alberta.

The Industry

Technological advances in seismic equipment and computing allow the seismic industry to acquire and process, on a cost‑effectivean efficient basis, immense volumes of seismic data which produce precise images of the earth’s subsurface. The latest accepted method of seismic data acquisition, processing, and the subsequent interpretation of the processed data is the 3‑D seismic method. Geophysicists use computer workstations to interpret 3‑D data volumes, identify subsurface anomalies, and generate a geologic model of subsurface features. In contrast with the 3‑D method, the 2‑D method involves the collection of seismic data in a linear fashion, thus generating a single plane of subsurface seismic data. Over recent years, the size of our surveys and density of recording channels and vibrator energy source units has increased resulting in an increase in required recording channels and energy source units to perform such surveys.

3‑D seismic data are used in the exploration and development of new reserves and enable oil and natural gas companies to better delineate existing fields and to augment their reservoir management techniques. Benefits of incorporating high resolution 3‑D seismic surveys into exploration and development programs include reducing drilling risk, decreasing oil and natural gas finding costs, and increasing the efficiencies of reservoir location, delineation, and management. In order to meet the requirements necessary to fully realize the benefits of 3‑D seismic data, there is an increasing demand for improved data quality with greater subsurface resolution.resolution with increased density of recording channels and vibrator energy source units.

Currently, the North American seismic data acquisition industry is made up of a number of companies divided into two groups. The first group is made up of publicly‑traded companies which includes us and SAExploration Holdings, Inc. (“SAE”). The second group is made up of Echo Seismic Ltd. (“ECHO”), Geokinetics, Inc. (“Geokinetics”), Breckenridge Geophysical Inc. (“Breckenridge”), and Paragon Geophysical Services, Inc. (“Paragon”), along with smaller companies which generally run one or two small channel count seismic crews and often specialize in specific regions or types of operations.

Equipment and Crews

In recent years, we have experienced continued increases in recording channel capacity and vibrator energy source units on a per crew or project basis. This increase in channel count and energy source unit demand is driven by client needs and is necessary in order to produce higher resolution images, increase crew efficiencies and undertake larger scale projects. Due to the increase in demand for higher channel counts, we have continued our investments in additional channels. In response to project‑based channel requirements, we routinely deploy a variable number of channels on a variable number of crews in an effort to maximize asset utilization and meet client needs. While the number of recording systems we own may exceed the number utilized in the field at any given time, we maintain the excess equipment to provide additional operational flexibility and to allow us to quickly deploy additional recording channels and energy source

deploy additional recording channels and energy source units as needed to respond to client demand and desire for improved data quality with greater subsurface images. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and margins with improved conditions.

Since 2011,In recent years, we have purchased or leased a significant number of cable‑lesscableless recording channels. We have utilizedutilize this equipment primarily as stand‑alone recording systems, but on occasion we have utilized it in conjunction with our cable‑based systems. As a result of the introduction of cable‑lesscableless recording systems, we have realized increased crew efficiencies and increased revenuechannels on projects using this equipment. We believe we will experience continued demand for cable‑lesscableless recording systems and increased channel count in the future. While we have replaced cable‑based recording equipment with cable‑less equipment on certain crews, the cable‑based recording equipment continues to be deployed on existing crews.

As of December 31, 2016,2019, we owned equipment for 22 land‑based seismic data acquisition crews, 201operate 117 vibrator energy source units and approximately 260,000268,000 recording channels. The recording channels consist of 93,000 single-channel GSR boxes, 45,500 three-channel GSR boxes, 3,600 four-channel GSR boxes and 22 central recording systems. Of the 22 recording systems we owned at December 31, 2016, 12 were Geospace Technologies GSR and GSX cable‑less recording systems, eight were ARAM ARIES cable‑based recording systems, one was a Wireless Seismic RT System 2 system, and one was a cable‑less8,000 three-channel INOVA Hawk system.boxes. Each crew consists of approximately 40 to 100 technicians with associated vehicles, geophones, a seismic recording system, energy sources, cables, and a variety of other equipment. Each ARAM crew has one central recording vehicle which captures seismic data. The GSR GSX and INOVA Hawk crews utilize a recorder to manage the data acquisition while the individual system captures and holds the data until they are placed in the Data Transfer Module. The data is then transferred to various data storage media, which are delivered to a data processing center selected by the client.

Equipment Acquisition and Capital Expenditures

We monitor and evaluate advances in geophysical technology and commit capital funds to purchase the equipment we deem most effective to maintain our competitive position. Purchasing and updating seismic equipment and technology involves a commitment to capital spending. We also tie our capital expenditures closely to demand for our services. As a result of the continuing softeningBeginning in demand for seismic services beginning in early 2014, and the Company’s belief that its current equipment base is sufficient to meet current demand, the Company haswe adopted a maintenance capital expenditures program anddue to the belief that our equipment base was sufficient to meet current demand; however, our Board of Directors may increase the capital budget in response to strategic opportunities to acquire seismic recording equipment. Our Board of Directors approved a maintenance capital expenditure budget of $10,000,000 for 2019 of which we utilized $3,590,000 during the 12 months ended December 31, 2019. Our Board of Directors has generally curtailed large equipment purchases.approved an initial maintenance capital expenditure budget of $5,000,000 for 2020. 

Clients

Our services are marketed by supervisory and executive personnel who contact clients to determine geophysical needs and respond to client inquiries regarding the availability of crews or processing schedules. These contacts are based principally upon professional relationships developed over a number of years.

Our clients range from major oil and gas companies to small independent oil and gas operators and also providers of multi‑client data libraries. The services we provide to our clients vary according to the size and needs of each client. During the twelve months ended December 31, 2016,2019, sales to one clientfour clients represented approximately 13%60% of our revenue.revenues. We anticipate that sales to these clients will represent a smaller percentage of our overall revenues during 2020. The remaining balance of our revenue wasrevenues were derived from varied clients and none represented 10% or more of our revenues. We anticipate that sales to this one client will represent a smaller percentage of our overall revenues during 2017.

We do not acquire seismic data for our own account or for future sale, maintain multi‑client seismic data libraries, or participate in oil and gas ventures. The results of seismic surveys conducted for a client belong to that client. It is also our policy that none of our officers, directors or employees actively participate in oil and natural gas ventures. All of our clients’ information is maintained in the strictest confidence.

Domestic and Foreign Operations

We derive our revenue from domestic and foreign sources. Total revenues for the twelve months ended December 31, 20162019 were approximately $133,330,000,$145,773,000, of which $122,522,000 were$129,452,000 was earned in the U.S. and $10,808,000 were$16,321,000 was earned in Canada. Total revenuerevenues for the twelve months ended December 31, 20152018 were approximately $234,685,000,$154,156,000, of which $222,154,000 were$137,101,000 was earned in the U.S. and $12,531,000$17,055,000 was earned in Canada.

Net property and equipment as of December 31, 2019 was approximately $53,549,000, of which $45,653,000 was located in the U.S. and $7,896,000 was located in Canada. Net right-of-use assets as of December 31, 2019 were earnedapproximately $6,605,000, of which $5,893,000 was located in the U.S. and $712,000 was located in Canada. Net property and equipment as of December 31, 2018 was approximately $71,541,000, of which $62,033,000 was located in the U.S. and $9,508,000 was located in Canada.

Long lived assets as of December 31, 2016 were approximately $324,950,000, with $308,418,000 owned in the U.S. and $16,532,000 owned in Canada. Long lived assets as of December 31, 2015 were approximately $345,619,000, with $329,467,000 owned in the U.S. and $16,152,000 owned in Canada.

Contracts

Our contracts are obtained either through competitive bidding or as a result of client negotiations. Our services are conducted under general service agreements for seismic data acquisition services which define certain obligations for us and for our clients. 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 project. We currently operate under supplemental agreements that are either “turnkey” agreements providing for a fixed fee to be paid to us for each unit of data acquired or “term” agreements providing for a fixed hourly, daily, or monthly fee during the term of the project or projects.

Currently, as in recent years, most of our projects are operated under turnkey agreements. Turnkey agreements generally provide us more profit potential, but involve more risks because of the potential of crew downtime or operational delays. We attempt to negotiate on a project‑by‑project basis some level of weather downtime protection within the turnkey agreements. Under the term agreements, we forego an increased profit potential in exchange for a more consistent revenue stream with improved protection from crew downtime or operational delays.

Competition

The acquisition of seismic data for the oil and natural gas industry is a highly competitive business. Contracts for such services generally are awarded on the basis of price quotations, crew experience, and the availability of crews to perform in a timely manner, although factors other than price, such as crew safety, performance history, and technological and operational expertise, are often determinative. Our competition includes publicly traded competitors, such as SAE. Our other major competitors include Echo, Geokinetics,ECHO, Breckenridge, and Paragon. In addition to these previously named companies, we also compete for projects from time to time with smaller seismic companies which operate in local markets with only one or two small channel count crews. Further, the barriers to entry in the seismic industry are not prohibitive, and it would not be difficult for seismic companies outside of the U.S. to enter the domestic market and compete with us.

Employees

As of December 31, 2016,2019, we employed 814455 full‑time employees, of which approximately 9772 consisted of management, sales, and administrative personnel with the remainder being crew and crew support personnel. Our employees are not represented by a labor union. We believe we have good relations with our employees.

See “Item 2. Properties” for a description of ourthe material properties utilized in our business.

Item 1A.  RISK FACTORS

An investment in our common stock is subject to a number of risks, including those discussed below. You should carefully consider these discussions of risk and the other information included in this Form 10‑K. These risk factors could affect our actual results and should be considered carefully when evaluating us. Although the risks described below are the risks that we believe are material, they are not the only risks relating to our business, our industry and our common stock. Additional risks and uncertainties, including those that are not yet identified or that we currently believe are immaterial, may also adversely affect our business, financial condition or results of operations. If any of the events described below occur, our business, financial condition or results of operations could be materially adversely affected.

We derive substantially all of our revenues from providers of multi-client data libraries and companies in the oil and natural gas exploration and development industry, as well as providers of multi‑client data libraries which serve common clients in the industry. The oil and natural gas industry is a historically cyclical industry which appears to be emerging from a severe downturn, with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices.

Demand for our services depends upon the level of expenditures by oil and natural gas companies for exploration, production, development and field management activities, which depend primarily on oil and natural gas prices. The oil and natural gas industry currently appears to be emerging from a severe downturn. Significant declinesfluctuations in domestic oil and natural gas exploration activities and oil and natural gascommodity prices have adversely affected, theand will continue to affect, demand for our services and our results

exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, could adversely impact us in many ways by negatively affecting:

Worldwide political, economic, and military events have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Depending on the market prices of oil and natural gas, oil and natural gas exploration and development companies may cancel or curtail their capital expenditure and drilling programs, thereby reducing demand for our services, or may become unable to pay, or have to delay payment of, amounts owed to us for our services. Oil and natural gas prices have been highly volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and natural gas prices, including:

A limited number of clients operating in a single industry account for a significant portion of our revenues, and the loss of one of these clients could adversely affect our results of operations.

We derive a significant amount of our revenues from a relatively small number of oil and gas exploration and development companies and providers of multi‑client data libraries. During the twelve months ended December 31, 2016,2019, our four largest clientclients accounted for approximately 13%60% of our revenues. If this client,these clients, or any of our other significant clients, were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, experience financial difficulties or for any other reason, our results of operations could be adversely affected.

Our clients could delay, reduce or cancel their service contracts with us on short notice, which may lead to lower than expected demand and revenues.

Our order book reflects client commitments at levels we believe are sufficient to maintain operations on our existing crews for the indicated periods. However, our clients can delay, reduce or cancel their service contracts with us on short notice. If the current downturn in the oil and natural gas industry that we appear to be emerging from continues for an extended period of time, or if it becomes more extreme,incurs a downturn, it may result in an increase in delays, reductions or cancellations by our clients. In addition, the timing of the origination and completion of projects and when projects are awarded and contracted for is also uncertain. As a result, our order book as of any particular date may not be indicative of actual demand and revenues for any succeeding period.

Our revenues, operating results and cash flows can be expected to fluctuate from period to period.

Our revenues, operating results and cash flows may fluctuate from period to period. These fluctuations are attributable to the level of new business in a particular period, the timing of the initiation, progress or cancellation of significant projects, higher revenues and expenses on our dynamite contracts, and costs we incur to train new crews we may add in the future to meet increased client demand. Fluctuations in our operating results may also be affected by other factors that are outside of our control such as permit delays, weather delays and crew productivity. Oil and natural gas prices have continued to be volatile and have resulted in significant demand fluctuations for our services. The current downturn in the oil and natural gas industry that we appear to be emerging from and the related sustained declines in oil and natural gas commodity prices have resulted in declines in the demand for our services. There can be no assurance of future oil and gas price levels or stability. Our operations in Canada are also seasonal as a result of the thawing season and we have historically experienced limited Canadian activity during the second and third quarters of each year. The demand for our services willwould be adversely affected by a significant reduction in oil and natural gas prices and by climate change legislation or material changes to U.S. energy policy. Because our business has high fixed costs, the negative effect of one or more of these factors could trigger wide variations in our operating revenues, cash flows, EBITDA, margin, and profitability from quarter‑to‑quarter, rendering quarter‑to‑quarter comparisons unreliable as an indicator of performance. Due to the factors discussed above, you should not expect sequential growth in our quarterly revenues and profitability.

We extend credit to our clients without requiring collateral, and a default by a client could have a material adverse effect on our operating revenues.

We perform ongoing credit evaluations of our clients’ financial conditions and, generally, require no collateral from our clients. It is possible that one or more of our clients will become financially distressed, especially in light of the recent downturn in the oil and natural gas industry and lowfluctuations in commodity prices, which could cause them to default on their obligations to us and could reduce the client’s future need for seismic services provided by us. Our concentration of clients

The high fixed costs of our operations could result in continuing or increasing operating losses.

Companies within our industry are typically subject to high fixed costs which consist primarily of depreciation (a non‑cash item) and maintenance expenses associated with seismic data acquisition and equipment and crew costs. In addition, ongoing maintenance capital expenditures, as well as new equipment investment, can be significant. As a result, any extended periods of significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays, or other causes could result in continuing or increasing operating losses.

We have indebtedness from time to time under credit facilities with a commercial bank, and certain of our core assetsaccounts receivable and ourrestricted CDARS accounts receivable are pledged as collateral for these obligations. Our ability to borrow may be limited if our accounts receivable decrease or the value of certain of our core assets is materially impaired.decreases.

WeFrom time to time, we may have indebtedness under credit facilities with a commercial bank. We maintain certain restricted CDARS accounts with our commercial bank and certain of our core assets as well as our accounts receivable are pledgedwhich can be used as collateral for theseagainst future borrowings. If we are unable to repay all secured borrowings when due, whether at maturity or if declared due and payable following a default, our lenders have the right to proceed against the assetsdeposit pledged to secure the indebtedness and may sell these assetsliquidate the CDARS account in order to repay those borrowings, which could materially harm our business, financial condition and results of operations. Our ability to borrow funds under our revolving line of credit is tied to the value of pledged assetsour collateral account with our commercial bank as well as the amount of our eligible accounts receivable. If our pledged assets become materially impaired or our accounts receivable decrease materially for any reason, including delays, reductions or cancellations by clients or decreased demand for our services, our ability to borrow to fund operations or other obligations may be limited.

Our financial results could be adversely affected by asset impairments.

We periodically review our portfolio of equipment and our intangible assets for impairment. In connection with the Merger, we recorded intangibles associated with the combination of Legacy TGC and Legacy Dawson that are an asset on our consolidated balance sheet. Future events, including our financial performance, sustained decreases in oil and natural gas prices, reduced demand for our services, our market valuation or the market valuation of comparable companies, loss of a significant client’s business, or strategic decisions, could cause us to conclude that impairment indicators exist and ultimately that the asset values associated with our equipment or our intangibles were to be impaired. If we were to impair our equipment or intangibles, these noncashnon-cash asset impairments could negatively affect our financial results in a material manner in the period in which they are recorded, and the larger the amount of any impairment that may be taken, the greater the impact such impairment may have on our financial results.

Our profitability is determined, in part, by the utilization level and productivity of our crews and is affected by numerous external factors that are beyond our control.

Our revenue isrevenues are determined, in part, by the contract price we receive for our services, the level of utilization of our data acquisition crews and the productivity of these crews. Crew utilization and productivity is partly a function of external factors, such as client cancellation or delay of projects, operating delays from inclement weather, obtaining land access rights and other factors, over which we have no control. If our crews encounter operational difficulties or delays on any data acquisition survey, our results of operations may vary, and in some cases, may be adversely affected.

In recent years, most of our projects have been performed on a turnkey basis for which we were paid a fixed price for a defined scope of work or unit of data acquired. The revenue, cost and gross profit realized under our turnkey contracts can vary from our estimates because of changes in job conditions, variations in labor and equipment productivity or because of the performance of our subcontractors. Turnkey contracts may also cause us to bear substantially all of the risks of business interruption caused by external factors over which we may have no control, such as weather, obtaining land access rights, crew downtime or operational delays. These variations, delays and risks inherent in turnkey contracts may result in reducing our profitability.

industry are not prohibitive, and it would not be difficult for seismic companies outside of the U.S. to enter the domestic market and compete with us.

Inclement weather may adversely affect our ability to complete projects and could, therefore, adversely affect our results of operations.

Our seismic data acquisition operations could be adversely affected by inclement weather conditions. Delays associated with weather conditions could adversely affect our results of operations. For example, weather delays could affect our operations on a particular project or an entire region and could lengthen the time to complete data acquisition projects. In addition, even if we negotiate weather protection provisions in our contracts, we may not be fully compensated by our clients for delays caused by inclement weather.

Our operations are subject to delays related to obtaining land access rights of way from third parties which could affect 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 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 within the time periods expected. Delays associated with obtaining such rights of way could negatively affect our results of operations.

Capital requirements for our operations are large. If we are unable to finance these requirements, we may not be able to maintain our competitive advantage.

Seismic data acquisition and data processing technologies historically have progressed steadily, and we expect this trend to continue. In order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. Our working capital requirements remain high, primarily due to the expansion of our infrastructure in response to client demand for cable‑lesscableless recording systems and more recording channels, which has increased as the industry strives for improved data quality with greater subsurface resolution images. Our sources of working capital are limited. We have historically funded our working capital requirements primarily with cash generated from operations, cash reserves and, from time to time, borrowings from commercial banks. In recent years, we have funded some of our capital expenditures through equipment term loans and capitalfinance leases. In the past, we have also funded our capital expenditures and other financing needs through public equity offerings. If we were to expand our operations at a rate exceeding operating cash flow, if current demand or pricing of geophysical services were to decrease substantially, or if technical advances or competitive pressures required us to acquire new equipment faster than our cash flow could sustain, additional financing could be required. If we were not able to obtain such financing or renew our existing revolving line of credit when needed, our failure could have a negative impact on our ability to pursue expansion and maintain our competitive advantage.

Technological change in our business creates risks of technological obsolescence and requirements for future capital expenditures. If we are unable to keep up with these technological advances, we may not be able to compete effectively.

Seismic data acquisition technologies historically have steadily improved and progressed, and we expect this progression to continue. We are in a capital intensive industry, and in order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. However, we may have limitations on our ability to obtain the financing necessary to enable us to purchase state‑of‑the‑art equipment, and certain

delay our deployment of additional crews and restrict the productivity of existing crews, adversely affecting our business and results of operations. In addition, any adverse change in the terms of our suppliers’ arrangements could affect our results of operations.

Some of our suppliers may also be our competitors. If competitive pressures were to become such that our suppliers would no longer sell to us, we would not be able to easily replace the technology with equipment that communicates effectively with our existing technology, thereby impairing our ability to conduct our business.

We are dependent on our management team and key employees, and inability to retain our current team or attract new employees could harm our business.

Our continued success depends upon attracting and retaining highly skilled professionals and other technical personnel. A number of our employees are highly skilled scientists and highly trained technicians. The loss, whether by death, departure or illness, of our senior executives or other key employees or our failure to continue to attract and retain skilled and technically knowledgeable personnel could adversely affect our ability to compete in the seismic services industry. We may experience significant competition for such personnel, particularly during periods of increased demand for seismic services. A limited number of our employees are under employment contracts, and we have no key man insurance.

We are subject to Canadian foreign currency exchange rate risk.

We conduct business in Canada which subjects us to foreign currency exchange rate risk. Currently, we do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments to mitigate the currency exchange rate risk. Our results of operations and our cash flows could be impacted by changes in foreign currency exchange rates.

Our common stock has experienced, and may continue to experience, price volatility and low trading volume.

Our stock price is subject to significant volatility. Overall market conditions, including a decline in oil and natural gas prices and other risks and uncertainties described in this “Risk Factors” section and in our other filings with the SEC, could cause the market price of our common stock to fall. Our high and low sales prices of our common stock for the twelve months ended December 31, 20162019 were $9.00$4.28 and $2.90,$1.90, respectively. Further, the high and low sales prices of our common stock for the twelve months ended December 31, 20152018 were $7.31$8.40 and $1.90,$3.04, respectively.

Our common stock is listed on The NASDAQ Stock Market LLC (“NASDAQ”) under the symbol “DWSN.” However, daily trading volumes for our common stock are, and may continue to be, relatively small compared to many other publicly traded securities. For example, during 20162019 our daily trading volume was as low as 6,3005,000 shares. It may be difficult for you to sell your shares in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.

We do not expect to pay cash dividends on our common stock for the foreseeable future, and, therefore, only appreciation of the price of our common stock may provide a return to shareholders.

While there are currently no restrictions prohibiting us from paying cash dividends to our shareholders, our boardBoard of directors,Directors, after consideration of economic and market conditions affecting the energy industry in general, and the oilfield services business in particular, determined that we would not pay a cash dividend in respect of our common stock for the foreseeable future. Payment of any cash dividends in the future will be at the discretion of our board and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by the board.

Certain provisions of our amended and restated certificate of formation may make it difficult for a third party to acquire us in the future or may adversely impact your ability to obtain a premium in connection with a future change of control transaction.

Our amended and restated certificate of formation contains provisions that require the approval of holders of 80% of our issued and outstanding shares before we may merge or consolidate with or into another corporation or entity or sell all, or substantially all, of our assets to another corporation or entity. Additionally, if we increase the size of our board from the current eight directors to nine directors, we could, by resolution of the boardBoard of directors,Directors, stagger the directors’ terms, and our directors could not be removed without approval of holders of 80% of our issued and outstanding shares. These provisions could discourage or impede a tender offer, proxy contest or other similar transaction involving control of us.

In addition, our boardBoard of directorsDirectors has the right to issue preferred stock upon such terms and conditions as it deems to be in our best interest. The terms of such preferred stock may adversely impact the dividend and liquidation rights of our common shareholders without the approval of our common shareholders.

We may be subject to liability claims that are not covered by our insurance.

Our business is subject to the general risks inherent in land‑based seismic data acquisition activities. Our activities are often conducted in remote areas under dangerous conditions, including the detonation of dynamite. These operations are subject to risk of injury to personnel and damage to equipment. Our crews are mobile, and equipment and personnel are subject to vehicular accidents. These risks could cause us to experience equipment losses, injuries to our personnel, and interruptions in our business.

In addition, we could be subject to personal injury or real property damage claims in the normal operation of our business. Such claims may not be covered under the indemnification provisions contained in our general service agreements to the extent that the damage is due to our negligence or intentional misconduct.

Our general service agreements require us to have specific amounts of insurance. However, we do not carry insurance against certain risks that could cause losses, including business interruption resulting from equipment maintenance or weather delays. Further, there can be no assurance, however, that any insurance obtained by us will be adequate to cover all losses or liabilities or that this insurance will continue to be available or available on terms which are

equipment and improvements in the areas in which we operate. In addition, our crews often operate in areas where the risk of wildfires is present and may be increased by our activities. Since our crews are mobile, equipment and personnel are subject to vehicular accidents. We use diesel fuel which is classified by the U.S. Department of Transportation as a hazardous material. These risks could cause us to experience equipment losses, injuries to our personnel and interruptions in our business. Delays due to operational disruptions such as equipment losses, personnel injuries and business interruptions could adversely affect our profitability and results of operations.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer‑based programs, including our seismic information, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, or if we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, loss of seismic data and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

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

We face various security threats, including cyber‑security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure, and threats from terrorist acts. Cyber‑security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

Our business is subject to government regulation that may adversely affect our future operations.

Our operations are subject to a variety of federal, state, provincial and local laws and regulations, including laws and regulations relating to the protection of the environment and archeological sites and those that may result from climate

requirements. While this new rule doesthese rules do not control GHG emission levels from any facilities, it willthey can cause covered facilities to incur monitoring and reporting costs. Moreover, lawsuits have been filed seeking to require individual companies to reduce GHG emissions from their operations. These and other lawsuits relating to GHG emissions may result in decisions by state and federal courts and agencies that could impact our operations.

ThisIn addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. In April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years. In November 2019, the State Department formally informed the United Nations of the United States’ withdrawal from the Paris Agreement. Due to the Paris Agreement’s protocol, the earliest the United States will be able to withdraw is November 2020. However, additional legislation or regulation by states and regions, the EPA, and/or any international agreements to which the United States may become a party that control or limit GHG emissions or otherwise seek to address climate change could adversely affect our operations. 

The increasing governmental focus on alleged global warmingGHG emissions may result in new environmental laws or regulations that may negatively affect us, our suppliers and our clients. 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 clients, suppliers or both incurring additional compliance costs that get passed on to us. Moreover, passage of climate change legislation, or other federal or state legislative or regulatory initiatives, or international agreements that regulate or restrict emissions of GHG may curtail production and demand for fossil fuels such as oil and gas in areas where our clients operate and, thus, adversely 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 cash flowsflows.

New regulation or legislation that limits or prohibits hydraulic fracturing could negatively affect the exploration and prospects.production of oil and gas and adversely affect demand for our services.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Several political and regulatory authorities and governmental bodies have studied hydraulic fracturing and considered potential regulations, and certain environmental and other groups have devoted resources to campaigns aimed at restricting or eradicating hydraulic fracturing.

Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. At the federal level, a bill was introduced in Congress in March 2011 entitled the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. The FRAC Act was re-introduced in Congress in June 2013, however, Congress has not taken any significant action on such legislation. If the FRAC Act or similar legislation were enacted, the definition of “underground injection” in the SDWA would be amended to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In early 2010, the EPA indicated in a website posting that it intended to regulate hydraulic fracturing under the SDWA and require permitting for any well where hydraulic fracturing was conducted with the use of diesel as an additive. While industry groups have challenged the EPA’s website posting as improper rulemaking, the Agency’s position, if upheld, could require additional permitting. In addition, in March 2010, the EPA commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of

regulate hydraulic fracturing under the SDWA and other aspects of the oil and gas industry. In light of concerns about induced seismicity, some state regulatory agencies have already modified their regulations or issued orders to address induced seismicity. 

The adoption of any future federal, state, foreign, regional or local laws that impact permitting requirements for, result in reporting obligations on, or otherwise limit or ban, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing. This could reduce demand for our services. Regulation that significantly restricts or prohibits hydraulic fracturing, or that requires hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements, could have a material adverse impact on our business. Additionally, legislation that requires the reporting and public disclosure of chemicals used in the fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. 

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 natural gas wells. Shale gas cannot be economically produced without extensive fracturing. In the event such legislation is enacted, demand for our seismic acquisition services may be adversely affected.

We are subject to the requirements of Section 404 of the Sarbanes‑Oxley Act.Act (“Section 404”). If we are unable to maintain compliance with Section 404, or if the costs related to maintaining compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

If we are unable to maintain adequate internal controls in accordance with Section 404, as such standards are amended, supplemented, or modified from time to time, we may not be able to ensure that we have effective internal controls over financial reporting on an ongoing basis in accordance with Section 404. Failure to achieve and maintain effective internal controls could have a material adverse effect on our stock price. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of clients, reduce our ability to obtain financing, and/or require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability and financial condition.

Item 1B.  UNRESOLVED STAFF COMMENTS

None.

Item 2.  PROPERTIES

Our headquarters are located in a 34,570-square34,570 square foot leased property in Midland, Texas. We have two properties in Midland that we own, including a 61,402-square61,402 square foot property we use as a field office, equipment and fabrication facility, and maintenance and repair shop, along with a 6,600 square foot property that we use as an inventory field office and storage facility.

We also have additional offices in three other cities in Texas: Denison, Houston and Plano. Our Denison warehouse facility consists of one 5,000‑5,000 square foot building, two 10,000‑10,000 square foot adjacent buildings and an outdoor storage area of approximately 60,500-square60,500 square feet. Our Houston sales office is in a 10,041‑an 8,161 square foot facility. Our office in Plano, Texas consists of 7,797 square feet of office space.

We lease a 3,443‑an 1,801 square foot facility in Denver, Colorado as a sales office. We also lease a 7,480-square7,480 square foot facility in Oklahoma City, Oklahoma as a sales office.

We lease 14,540-square feeta  15,020 square foot facility in Calgary, Alberta consisting of office, warehouse and shop space located in Calgary, Alberta. In addition, Eagle Canada leases a 7,423‑square foot facility, also located in Calgary, Alberta, that is used as a shop and warehouse. We also lease a storage and parking area near the Eagle Canada shop and warehouse.space. 

We believe that our existing facilities are being appropriately utilized in line with past experience and are well maintained, suitable for their intended use, and adequate to meet our current and future operating requirements.

Item 3.  LEGAL PROCEEDINGS

From time to time, we are a party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of pending legal actions will not have a material adverse effect on our financial condition, results of operations or liquidity.

The following table summarizes certain information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2016.2019. See information and definitions regarding material features of the plans in Note 8, “Stock‑Based Compensation,” to the Consolidated Financial Statements incorporated by reference herein.

PERFORMANCE GRAPH

The following graph below matches Dawson Geophysical Company’s cumulative five year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the PHLX Oil Service Sector index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 20112014 to December 31, 2016.

The stock prices used in the computation of the graph below reflect those of Legacy TGC from December 31, 2010 to December 31, 2014 multiplied by three to account for the 1‑for‑3 reverse stock split undertaken by Legacy TGC in connection with the Merger. The stock price at December 31, 2015 and 2016 reflects that of the combined Company following the Merger, as reported on NASDAQ under the symbol “DWSN”.

Item 6.  SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the Company’s consolidated financial statements and related notes included in Item 8, “Financial Statements and Supplementary Data.” Amounts below are in thousands, except per share amounts.

During the early part of the fourth quarter of 2016,2019, we operated a maximumpeak of sixfour crews in the U.S., primarily in the Permian Basin region, including three large channel count crews. Crew activity in Canada was minimal during the fourth quarter of 2019. The fourth quarter and early part of the first quarter in the U.S. historically has been challenging due to shorter work days and the holiday season. The winter season in Canada concludes at the end of the first quarter of 2020. Upon completion of the Canadian season, equipment will redeploy to the lower 48 in the second quarter of 2020. As in recent quarters, the majority of our projects are on behalf of multi-client data companies in the U.S., with some activity directly for exploration and production companies.

While fourth quarter 2019 results were below those of our third quarter, our fourth quarter results showed significant improvement compared to the fourth quarter of 2018. We believe that our ability to successfully field large scale deployments is a contributing factor to our success as the industry continues to transition toward a channel and energy source business model and away from the traditional crew count model. Despite this improvement, our fourth quarter 2019 results were negatively impacted by the completion of several large projects early in the quarter, client delays that have moved the start of new projects into the first quarter of 2020, and lower utilization of recording channels and energy source units. Utilization was suppressed into the early part of the first quarter of 2020.

During fiscal year 2019, we experienced a general increase in recording channels and energy source unit requirements per 3-D project and believe that trend will continue into next year. The increase in recording channels and energy source units allowed us to perform larger 3D surveys with increased density, which aids in improving subsurface resolution and allows for increased crew productivity and efficiency. As we moved to more of a recording channel and energy source model as opposed to a crew model during the year, we were able to increase crew efficiency, improve utilization on a per crew basis and reduce crew level operating cost. However, due to various factors during the year, overall utilization was inconsistent from period to period as we experienced project readiness delays, client delays and completion of project timing issues. While we are confident in our demand visibility in the early part of 2020, we anticipate similar issues could exist in 2020.

The oil service markets remain challenging as the capital spending levels of exploration and production companies remain somewhat constrained and unpredictable. Utilization visibility into the second half of 2020 remains unclear. As of the middle part of the first quarter, we are near full utilization with three large crews operating in the U.S., primarily the Permian Basin region, and three crews operating in Canada. Based on currently available information, we anticipate the same level of activity through the end of the first quarter of 2020 with the three large crews in the U.S. and four in Canada. Demand for our services in 2016 continued atoperating well into the reduced levels seen in the most recent years and is anticipated to remain at reduced levels into 2017. During 2016, we operated a maximum of eight crews in the U.S. Quarterly and annual results were negatively impacted as a result of reduced demand, inclement weather, delays in securing land access agreements, lower crew utilization rates, reduced pricing for our services and project delays on behalf of our clients. Until there is a sustained recovery in oil or natural gas prices, visibility for active crew count beyond the firstsecond quarter of 20172020. While the seismic market remains unclear.challenging, conversations with our clients, primarily providers of multi-client data libraries, are positive for continued levels of activity through 2020.

The majority of our crews are currently working in oil producing basins. While our revenues are mainly affected by the level of client demand for our services, our revenues are also affected by the pricing for our services that we negotiate with our clients and the productivity and utilization level of our data acquisition crews. Factors impacting productivity and utilization levels include client demand, commodity prices, whether we enter into turnkey or termdayrate contracts with our clients, the number and size of crews, the number of recording channels per crew, crew downtime related to inclement weather, delays in acquiring land access permits, agricultural or hunting activity, holiday schedules, short winter days, crew repositioning and equipment failure. To the extent we experience these factors, our operating results may be affected from quarter to quarter. Consequently, our efforts to negotiate more favorable contract terms in

exist for us to enhance our market position by responding to our clients’ continuing desire for higher resolution subsurface images. If economic conditions continue to weaken such that our clients continue to reduce their capital expenditures or if the sustained drop in oil and natural gas prices worsens, it could continue to result in diminished demand for our seismic services, could cause downward pressure on the prices we charge and would affect our results of operations.

Items Affecting Comparability of Our Financial Results

As discussed above, the Merger has been accounted for as a reverse acquisition under which Legacy Dawson was considered the accounting acquirer of Legacy TGC. As such, the historical financial statements of Legacy Dawson are treated as the historical financial statements of the combined company. The combined company adopted a calendar fiscal year ending December 31. Accordingly, the financial results of the company for the years ended December 31, 2016 and 2015 presented in this Form 10‑K are compared to the results for Legacy Dawson for the three months ended December 31, 2014 and the year ended September 30, 2014. In order to aid in the review and comparison of our financial results, we have prepared and presented unaudited financial results as of the year ended December 31, 2014 even though Legacy Dawson’s 2014 fiscal year ended on September 30, 2014. We would not have otherwise prepared or presented our financial results from this period in this fashion. The financial results for the year ended December 31, 2015 presented in this Form 10‑K reflect the operations of Legacy Dawson for the period January 1 through February 10, 2015 and the operations of the combined company for the period February 11 through December 31, 2015. Due to the foregoing, our financial results for the three months ended December 31, 2014 and the year ended September 30, 2014 are not directly comparable to our financial results for the years ended December 31, 2016 and 2015 as a result of the combination of the assets and liabilities and results of operations of two previously separate companies and the change in fiscal year end.

companies may not calculate EBITDA in the same manner as us. Further, the results presented by EBITDA cannot be achieved without incurring the costs that the measure excludes: interest, taxes, and depreciation and amortization.

The reconciliation of our EBITDA to our net loss and net cash provided by (used in) operating activities, which are the most directly comparable GAAP financial measures, are provided in the following tables below:(in thousands):

in investing activities were offset by $1,922,000 of proceeds from disposal of assets and $2,850,000 of proceeds on flood insurance claims. Net cash provided by investing activities was $15,787,000 for the year ended December 31, 2015 and includes cash of $12,382,000 acquired in the Merger, $7,750,000 of short term investment maturities that were not reinvested, $1,501,000 of proceeds from disposal of assets and $1,000,000 of proceeds on flood insurance claims. These increases in cash provided by investing activities were offset by cash capital expenditures of $6,846,000.

Net cash used in financing activities was $8,483,000$11,256,000 for the year ended December 31, 20162019 and includes principal payments of $7,554,000$8,165,000 on our notes payments of $780,000 underand $2,855,000 on our capitalfinance leases, and outflows of $149,000$236,000 associated with taxes related to stock vesting. Net cash used inprovided by financing activities was $13,606,000$2,517,000 for the year ended December 31, 20152018 and includedincludes proceeds from notes payable used to purchase seismic data acquisition equipment of $6,518,000 offset by principal payments of $16,348,000$1,180,000 on our notes payments of $1,535,000 underand $2,699,000 on our capitalfinance leases, and outflows of $867,000$121,000 associated with taxes related to stock vesting offset by proceeds of $5,144,000 from our Credit Agreement (as defined below).

Year Ended December 31, 2015 versus Year Ended December 31, 2014

Net cash provided by operating activities was $20,612,000 and $30,472,000 for the years ended December 31, 2015 and 2014, respectively. This decrease primarily reflects our decline in revenues during the year ended December 31, 2015.

Net cash provided by investing activities was $15,787,000 for the year ended December 31, 2015 and represented cash of $12,382,000 acquired in the Merger, $7,750,000 of short-term investment maturities that were not reinvested, $1,501,000 of proceeds from disposal of assets and $1,000,000 of proceeds on flood insurance claims. These increases in cash provided by investing activities were offset by cash capital expenditures of $6,846,000.  Net cash used in investing activities was $13,438,000 for the year ended December 31, 2014 and included cash capital expenditures of $14,001,000 and $2,750,000 of cash reserves invested. These decreases in cash used in investing activities were offset by $3,313,000 of proceeds from disposal of assets.

Net cash used in financing activities was $13,606,000 for the year ended December 31, 2015 and included principal payments of $16,348,000 on our notes, payments of $1,535,000 under our capital leases, and outflows of $867,000 associated with taxes related to stock vesting offset by proceeds of $5,144,000 from our Credit Agreement (as defined below). Net cash used in financing activities for the year ended December 31, 2014 was $13,870,000, primarily comprised of principal payments of $10,293,000 on term notes, payments of $1,014,000 under our capital leases, and cash dividends paid of $2,581,000.

Capital Expenditures.  During 2016, we made capital expenditures of $9,793,000. We limited our capital expenditures to necessary maintenance capital requirements. The Board of Directors approved an initial 2017 budget of $10,000,000 for capital expenditures, which is again limited primarily to necessary maintenance capital requirements and incremental recording channel replacement or increase. In recent years, we have funded some of our capital expenditures through cash reserves, equipment term loans and capital leases. In the past, we have also funded our capital expenditures and other financing needs through public equity offerings.vesting.

We continually strive to supply our clients with technologically advanced 3-D data acquisition recording services and data processing capabilities. We maintain equipment in and out of service in anticipation of increased future demand for our services.

Capital Resources.  Historically, we have primarily relied on cash generated from operations, cash reserves and borrowings from commercial banks to fund our working capital requirements and, to some extent, our capital expenditures. Recently, we have funded some of our capital expenditures through finance leases and equipment term loans and capital leases.loans. From time to time in the past, we have also funded our capital expenditures and other financing needs through public equity offerings.

Indebtedness.Dominion Credit Facility.  On JuneSeptember 30, 2015,2019, we entered into an amendment to our Credita new Loan and Security Agreement with our lender, Sovereign Bank, (as amended from time to time, the “Credit(the “Loan Agreement”) for the purpose of renewing, extending and increasing our line of credit under such agreement.

Credit Agreement.  Our Credit Agreement with SovereignDominion Bank includes a term loan feature and a revolving loan feature, and also allows for the issuance of letters of credit and other promissory notes. We can borrow up to a maximum of $20.0 million pursuant to the Credit Agreement, subject to the terms and limitations discussed below.

principally upon our future operating performance, which is subject to the risks inherent in our business, and will also depend on the extent to which the current economic climate adversely affects the ability of our customers, and/or potential customers, to promptly pay amounts owing to us under their service contracts with us.

The assets and liabilities under capitalfinance 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 capitalfinance leases are amortized using the straight‑line method over the initial lease term. Amortization of assets under capitalfinance leases is included in depreciation expense.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (“Topic 842”) requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. Topic 842 also requires qualitative and quantitative disclosures to help investors and other financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases.

On January 1, 2019, we adopted Topic 842 using the optional cumulative-effect transition method of adoption, under which the new standards were applied prospectively rather than restating the prior periods presented. As a result, certain accounts lack a comparable value for the same period of 2018 and 2017, specifically accounts and values associated with operating leases and right-of-use (“ROU”) assets. As a result of adopting the new standard, we recorded ROU assets and operating lease liabilities of approximately $7,769,000 and $8,252,000, respectively, on the consolidated balance sheet for 2019. The ROU assets equaled the operating lease liabilities, excluding the impact of reclassifying prepaid rent and deferred rent of approximately $14,000 and $497,000, respectively. These amounts were previously recorded in prepaid expenses and other current assets and other accrued liabilities, respectively. The new standard did not materially impact our results of operation or cash flows.

In addition, we made an accounting policy election not to recognize leases with an initial term of 12 months or less and not to separate lease and non-lease components. We elected the practical expedients package, which among other things, allowed us to carry forward the historical lease classification. We did not elect the hindsight or land easement practical expedients.

Several of our leases include options to renew, with renewal terms that can extend from one to 10 years or more. The exercise of lease renewal options is primarily at our discretion. To measure operating lease recognition, we evaluated our lease agreements to determine if they had economic incentives for renewal or options to purchase. We deem leasehold improvements as one of the few economic incentives that would entice us to renew a lease and all of our leasehold improvements are currently fully amortized.

Where readily determinable, we use the implicit interest rate in determining the present value of future minimum lease payments. In the absence of an implicit rate, we use our incremental borrowing rate based on the information available at the lease commencement date. We give consideration to our outstanding debt, as well as publicly available data for instruments with similar characteristics when calculating our incremental borrowing rates. Our ROU assets are amortized to operating lease cost over the lease terms on a straight-line basis.

Revenue Recognition.Our services are provided under cancelable service contracts.contracts which usually have an original expected duration of one year or less. These contracts are either “turnkey” or “term” agreements. Under both types of agreements, we recognize revenues when revenue is realizable andas the services are performed. Services are defined as the commencementRevenue is generally recognized based on square miles of data acquisition or processing operations. Revenues are considered realizable when earned accordingrecorded compared to total square miles anticipated to be recorded on the terms ofsurvey using the total estimated revenue for the service contracts. Under turnkey agreements, revenue is recognized on a per-unit-of-data-acquired rate, as services are performed. Under term agreements, revenue is recognized on a per-unit-of-time-worked rate, as services are performed.contract. In the case of a cancelled service contract, we recognizethe client is billed and revenue is recognized for any third party charges and bill our client for services performedsquare miles of data recorded up to the date of cancellation.

We also receive reimbursements for certain out‑of‑pocketout-of-pocket expenses under the terms of ourthe service contracts. We recordThe amounts billed to clients in revenueare included at thetheir gross amount including out‑of‑pocket expenses thatin the total estimated revenue for the service contract.

Clients are reimbursedbilled as permitted by the client.service contract. Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. If billing occurs prior to the revenue recognition or billing exceeds the revenue recognized, the amount is considered deferred revenue and a contract liability. Conversely, if the revenue recognition exceeds the billing, the excess is considered an unbilled receivable and a contract asset. As services are performed, those contract liabilities and contract assets are recognized as revenue and expense, respectively.

 In some instances, third-party permitting, surveying, drilling, helicopter, equipment rental and mobilization costs that directly relate to the contract are utilized to fulfill the contract obligations. These fulfillment costs are capitalized in

other current assets and amortized based on the total square miles of data recorded compared to total square miles anticipated to be recorded on the survey using the total estimated fulfillment costs for the service contract.

Estimates for total revenue and total fulfillment cost on any service contract are based on significant qualitative and quantitative judgments. Management considers a variety of factors such as whether various components of the performance obligation will be performed internally or externally, cost of third party services, and facts and circumstances unique to the performance obligation in making these estimates.

In some instances, we bill clientsMay 2014, the FASB issued new guidance related to revenue recognition in advancewhich an entity should recognize revenue when promised goods or services are transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Codified as Topic 606, this new guidance also required disclosures sufficient to enable users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

We adopted Topic 606 effective January 1, 2018, using the full retrospective method, which required us to adjust our consolidated financial statements from amounts previously reported for each prior reporting period presented. We recognized the cumulative effect of adopting the guidance as an adjustment to our opening balance of retained earnings as of January 1, 2016. We elected several ongoing and transitional practical expedients including (i) to ignore the financing component when estimating the transaction price for service contracts completed within one year, (ii) to exclude sales tax collected from the customer when determining the transaction price, (iii) to expense incremental costs to obtain a customer contract if the amortization period for those costs would otherwise be one year or less, (iv) to not restate contracts that begin and end within the same annual reporting period, (v) to use the transaction price at the completion of the services performed. In those cases, we recognizecontract to retrospectively apply the liability asnew guidance, and (vi) to not disclose the remaining performance obligations for the reporting periods presented before the date of initial application. The most significant impact to us of the adoption of Topic 606 relates to the deferred revenue. As services are performed, those deferred revenue amounts are recognized as revenue.

In some instances, the contract contains certain permitting, surveyingrecognition of revenues and drilling costs that are incorporated into the per-unit-of-data-acquired rate. In these circumstances, these set‑up costs that occur priorexpenses to initiating revenue recognition are capitalized and amortized asfulfill contracts with customers until data is acquired.recording has begun.

Income Taxes.    We account for our income taxes with the recognition of amounts of taxes payable or refundable for the current year and by using an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We determine deferred taxes by identifying the types and amounts of existing temporary differences, measuring the total deferred tax asset or liability using the applicable tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of an enacted rate change. 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 determining our annual effective tax rate and 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. Due to our recent operating losses and valuation allowances, we may recognize reduced or no tax benefits on future losses on the Consolidated Statements of Operations and Comprehensive Loss. Our effective tax rates differ from the statutory federal rate of 35%21% for certain items such as state and local taxes, valuation allowances, non‑deductible expenses and discrete items.

Recently Issued Accounting Pronouncements

In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce the diversity in practice around how certain transactions are classified within the statement of cash flows. We adopted ASU No. 2016-15 in the third quarter of 2016 with no material impact to our consolidated financial statements. However, certain reclassifications have been made to the Consolidated Statements of Cash Flows for the year ended December 31, 2015 in order to conform to the December 31, 2016 presentation.

In March 2016,2019, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718)2019-12, Income Taxes (“Topic 740”): Improvements to Employee Share-Based PaymentSimplifying the Accounting for Income Taxes, which is intended to simplifysimplifies the accounting for share-based payments awardedincome taxes by eliminating certain exceptions to employees, including income tax consequences, classification of awards as either equity or liabilities,the general principles in Topic 740 and classification on the statement of cash flows.by clarifying and amending existing guidance to improve consistent application. This ASU is effective for the annual period beginning after December 15, 2016, and for annual and2020, including interim periods thereafter.within that annual period. Certain amendments within this ASU are required to be applied on a retrospective basis for all periods presented; others are to be applied using a modified retrospective approach with a cumulative-effect adjustment to retained earnings, if any, as of the beginning of the first reporting period in which the guidance is adopted; and yet others are to be applied using either basis. All other amendments not specified in the ASU should be applied on a prospective basis. Early adoption is permitted. Adoption of ASU 2016-09 will not have a material effect on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which will require organizationsAn entity that lease assetselects to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments – Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosuresearly adopt in an interim period should be considered to assess the significancereflect any adjustments as of the impact upon adoption. This ASU is effective forbeginning of the annual period beginning after December 15, 2018, and for annual andthat includes that interim periods thereafter. Earlyperiod. Additionally, an entity that elects early adoption is permitted.must adopt all the amendments in the same period. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and believe that the most significant change will be to our Consolidated Balance Sheets as our asset and liability balances will increase for operating leases that are currently off-balance sheet.statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40), which provides guidance on management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and, in certain circumstances, to provide related footnote disclosures. We evaluated and adopted this guidance for the period ending December 31, 2016.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in

exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Entities have the option of using either a full retrospective or modified approach to adopt ASU No. 2014-09.

In MarchJune 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers2016-13, Financial Instruments – Credit Losses (Topic 606)326): Principal versus Agent Considerations (Reporting Gross versus Net), amendingMeasurement of Credit Losses on Financial Instruments, which requires entities to measure expected credit losses for certain financial assets using a new, forward-looking current expected credit loss model (“CECL”) that will result in the principal-versus-agent implementation guidanceearlier recognition of allowances for losses. CECL is based on historical experience, adjusted for current conditions and clarifyingreasonable and supportable forecasts. This ASU is effective for the annual period beginning after December 15, 2019, including interim periods within that an entity should evaluate whether it is the principal or the agent for each specified good or service promised inannual period using a contractmodified retrospective approach with a customer. cumulative-effect adjustment to retained earnings for additional loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. Our financial instruments within the scope of this guidance primarily includes trade receivables, and we do not expect a material impact on our consolidated financial statements.

In April 2016,June 2018, the FASB issued ASU No. 2016-10, Revenue2018-07, Compensation – Stock Compensation (“Topic 718”): Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which amendsnonemployees except for certain aspectscircumstances. Any transition impact will be a cumulative-effect adjustment to retained earnings as of the beginning of the year of adoption. We adopted this guidance related to identifying performance obligationsin the first quarter of 2019 and licensing implementation. it did not have a material impact on our consolidated financial statements.

In May 2016,August 2018, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers2018-13, Fair Value Measurement (Topic 606)820): Narrow Scope ImprovementsDisclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement, which modifies the disclosure requirements on fair value measurement by removing, modifying and Practical Expedients, to addressadding certain issues indisclosures. This ASU is effective for the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, which amends narrow aspects of the guidance such as disclosure of remaining performance obligations and prior-period performance obligations. In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments – Equity Method and Joint Ventures (Topic 323), which stated additional qualitative disclosures should be considered to assess the significance of the impact upon adoption. These updates do not change the core principle of the guidance under ASU No. 2014-09, but rather provide implementation guidance. In August 2015, ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, was issued and it amended the effective date of ASU No. 2014-09 for public companies to annual reporting periodsperiod beginning after December 15, 2017. Early2019, including interim periods within that annual period. The adoption of this guidance will not have a material impact on our consolidated financial statements.

In August 2018, the SEC adopted amendments to simplify certain disclosure requirements, as set forth in Securities Act Release No. 33-10532, Disclosure Update and Simplification, which includes a requirement for entities to present the changes in shareholders’ equity in the interim financial statements in quarterly reports on Form 10-Q. This amendment is permitted, but only beginningeffective for all filings made on or after December 15, 2016. We are reviewing our customer contracts, revenue recognition policies, disclosures,November 5, 2018. In light of the timing of effectiveness of the amendment and internal controls and comparingproximity to the provisionsfiling date for most filers’ quarterly reports, the SEC has allowed for a filer’s first presentation of the new standardchanges in shareholders’ equity to be included in its Form 10-Q for our revenuesthe quarter that begins after the effective date. We adopted the SEC’s amendment to determineinterim disclosures in the potential impactfirst quarter of 2019 and have presented the changes in shareholders’ equity on the timing and amounts of revenue recognition. While we have not identified any material differences from our review thus far, our evaluation is ongoing and we have not concluded on the overall impacts of adopting the new guidance. We believe we are following an appropriate timeline to allow for proper recognition, presentation and disclosure upon adoption.interim basis.

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes to operating concentration of credit risk and changes in interest rates. We have not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other derivative financial instruments. We also conduct business in Canada, which subjects our results of operations and cash flowflows to foreign currency exchange rate risk.

Concentration of Credit Risk.  Our principal market risks include fluctuations in commodity prices, which affect demand for and pricing of our services, and the risk related to the concentration of our clients in the oil and natural gas industry. Since all of our clients are involved in the oil and natural gas industry, there may be a positive or negative effect on our exposure to credit risk because our clients may be similarly affected by changes in economic and industry conditions. As an example, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our clients. In the normal course of business, we provide credit terms to our clients. Accordingly, we perform ongoing credit evaluations of our clients and maintain allowances for possible losses. Our historical experience supports our allowance for doubtful accounts of $250,000 at December 31, 2016.2019. This does not necessarily indicate that it would be adequate to cover a payment default by one large or several smallsmaller clients.

We generally provide services to certain key clients that account for a significant percentage of our accounts receivable at any given time. Our key clients vary over time. We extend credit to various companies in the oil and natural gas industry, including our key clients, for the acquisition of seismic data, which results in a concentration of credit risk. This concentration of credit risk may be affected by changes in the economic or other conditions of our key clients and may accordingly impact our overall credit risk. If any of these significant clients were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, or for

any other reason, our results of operations could be affected. Because of the nature of our contracts and clients’ projects, our largest clients can change from year to year, and the largest clients in any year may not be indicative of the largest clients in any subsequent year. During the twelve months ended December 31, 2016,2019, our four largest clientclients accounted for approximately 13%60% of revenue. The remaining balance of our revenue derived from varied clients and none represented more than 10% of revenue.

independent registered public accounting firm who also audited our financial statements. Their attestation report appears on page F‑2.

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 on pages F‑1 through F‑2624 and are incorporated by reference into Part II, Item 8:

Reports of Independent Registered Public Accounting FirmsFirm 

Consolidated Balance Sheets 

Consolidated Statements of Operations and Comprehensive Loss 

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to the 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.

INDEX TO EXHIBITS