PART I

Information Regarding Forward-Looking Statements

This Form 10-K includes “forward-looking statements” as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which reflect our view with respect to future events.  We base these forward-looking statements on our current expectations and projections about future events.  These forward-looking statements are subject to risks, uncertainties, and assumptions about us, including:

·                   dependence upon energy industry spending for seismic data acquisition services;

·                   changes in economic conditions;

·                   the unpredictable nature of forecasting weather;

·                   the potential for contract delay or cancellation;

·                   the potential for fluctuations in oil and natural gas prices; and

·                   the availability of capital resources.

We use the words “may,” “will,” “can,” “could,” “should,” “expect,” “anticipate,” “estimate,” “believe,” “target,” “continue,” “intend,” “plan,” “budget,” and other similar words to identify forward-looking statements.  You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition, and/or state other “forward-looking” information.  We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law.  These statements also involve risks and uncertainties that could cause our actual results or financial condition to differ materially from our expectations in this Form 10-K.

We believe that it is important to communicate our expectations of future performance to our investors.  However, events may occur in the future that we are unable to accurately predict or over which we have no control.  When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements contained in this Form 10-K and other factors noted throughout this Form 10-K.  There are many risks, uncertainties, and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please read the section entitled “Risk Factors” for a discussion of certain risks of our business and an investment in our common stock.

In April of 1980, Supreme Industries, Inc. (“Supreme”), formerly ESI Industries, Inc., formed a wholly-owned subsidiary, Tidelands Geophysical Co., Inc. (“Tidelands”) that acquired certain equipment, instruments, and related supplies from a Houston-based corporation that was engaged in the business of conducting seismic, gravity, and magnetic surveys under contracts for oil and natural gas companies.  On June 30, 1986, the Boards of Directors of Supreme and Tidelands approved a spin-off of substantially all of the shares of Tidelands owned by Supreme which were distributed as a stock dividend to Supreme’s security holders.  In July of 1986, our name was changed from “Tidelands Geophysical Co., Inc.” to “TGC Industries, Inc.” As described above, we completed the Merger with Legacy Dawson on February 11, 2015, and in connection with the Merger, our name was changed to “Dawson Geophysical Company.”

Overview

We are a leading provider of seismic data acquisition services throughout the continental United States and Canada.  As of December 31, 2014, we operated eight seismic crews consisting of three crews in the United States and five crews in Canada.  These 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, Inc. (“Eagle Canada”) are also used by the potash mining industry in Canada, and Eagle Canada has particular expertise through its heliportable capabilities.  Our customers 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.

We acquire geophysical data using the latest in 3-D survey techniques. We introduce acoustic energy into the ground by using vibration equipment or dynamite detonation, depending on the surface terrain and subsurface requirements. The reflected energy, or echoes, is 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. With our state-of-the-art seismic equipment, including computer technology and multiple channels, we acquire, on a cost effective basis, immense volumes of seismic data that, when processed and interpreted, produce more precise images of the earth’s subsurface. Our customers then use our seismic data to generate 3-D geologic models that help reduce finding costs and improve recovery rates from existing wells.

The operations of Legacy Dawson are substantially similar to those of our Company, except that Legacy Dawson’s historical annual revenues have been approximately twice as large as those of our Company, Legacy Dawson has in-house trucking and data processing capabilities and has had a larger presence than us in the United States, and our Company has in-house dynamite energy source drilling service capabilities and has had a larger presence than Legacy Dawson in Canada. As of December 31, 2014, Legacy Dawson employed over 1,079 persons, of which approximately 928 were engaged in providing energy sources and acquiring data, operating in the lower 48 states of the United States and Canada.

The Industry

Technological advances in seismic equipment and computing allow the seismic industry to acquire and process, on a cost-effective 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.

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.

Currently, the seismic data acquisition industry is made up of a number of companies divided into two groups. The first group is made up of three publicly-traded companies with long operating histories that field numerous crews and work in a number of different regions and terrain.  This group includes us, SAExploration Holdings, Inc., or SAE, and CGG (which recently sold its North American onshore seismic contract acquisition business to Geokinetics, Inc., or Geokinetics). The second group is made up of Geokinetics, Global Geophysical Services, Inc., or Global Geophysical, Tesla Exploration, Ltd., or Tesla, Breckenridge Geophysical Inc., or Breckenridge, Paragon Geophysical Services, Inc., or Paragon, LoneStar Geophysical Surveys, or LoneStar, and smaller companies which generally run one or two seismic crews and often specialize in specific regions or types of operations.

We provide our seismic data acquisition services primarily to onshore oil and natural gas exploration and development companies for use in the onshore drilling and production of oil and natural gas in the continental United States and Canada. The main factors influencing demand for seismic data acquisition services in our industry are the level of drilling activity by oil and natural gas companies and the sizes of such companies’ exploration and development budgets, which, in turn, depend largely on current and anticipated future crude oil and natural gas prices and depletion rates.

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Equipment and Crews

During 2011 and 2012, an increase in the demand for seismic services allowed for an expansion of the Company’s crew count from eleven crews at December 31, 2010, to twelve crews at December 31, 2011, and to fourteen crews at December 31, 2012.  Demand for seismic services softened beginning early in 2013 and remained soft throughout 2014. As a result we decreased our crew count in 2013 and ended 2013 and 2014 with eight crews.

In January of 2012, we purchased an additional 14,200 channels of GSR equipment financed by existing cash and a note payable to a commercial bank.  In April of 2012, the Company purchased seven new INOVA vibration vehicles with existing cash.  Also in April of 2012, the Company purchased 13,000 channels of GSR equipment financed partially with existing cash and partially by a note payable to a commercial bank.  In October of 2012, we purchased 8,000 stations of 3-channel GSX wireless recording system along with all peripheral equipment.  GSX wireless recording systems are the most current GSR wireless recording systems available.  The purchase of the OYO Geospace GSX recording system equipment was financed partially with existing cash and partially by a note payable to a commercial bank.  Beginning early in 2013, we experienced a softening in demand for seismic services and, as a result, the Company adopted a maintenance capital expenditures program curtailing large equipment purchases for the duration of the year and continuing into 2014.  In September 2014, we purchased a 10,500-channel INOVA Hawk seismic data acquisition system financed with a note payable to a commercial bank.  INOVA Hawk wireless recording systems are among the most current wireless recording systems available.

As of December 31, 2014, we owned equipment for 16 land-based seismic data acquisition crews and 73 vibration vehicles.  Each crew consists of approximately 40 to 80 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 a CD-ROM or data tape which is delivered to a data processing center selected by the customer.

In addition to the Legacy TGC equipment referenced above, as of December 31, 2014, Legacy Dawson owned approximately 157 vibrator energy source units, approximately 179,000 recording channels and sixteen central recording systems. Of the sixteen recording systems Legacy Dawson owned at December 31, 2014, seven were Geospace Technologies GSR cable-less recording systems, eight were ARAM ARIES cable-based recording systems, and one was a Wireless Seismic RT System 2 system.  During the quarter ended December 31, 2014, Legacy Dawson operated eight to ten data acquisition crews.  Each crew consisted of approximately forty to one hundred technicians, twenty-five or more vehicles with off-road capabilities, up to 100,000 geophones, a seismic recording system, energy sources, electronic cables and a variety of other equipment.

Capital Expenditures

We believe that it is essential to take advantage of advances in seismic technology and to commit capital to purchase and update our equipment cost-effectively. 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, due to the continuing softening in demand for seismic services beginning early in 2013, the Company adopted a maintenance capital expenditures program curtailing large equipment purchases for the duration of 2013 and, with the exception of the INOVA Hawk seismic data acquisition system purchase disclosed earlier, continuing through 2014. During the year ended December 31, 2014, we made capital expenditures of approximately $7,955,000, which includes the INOVA Hawk system purchase and maintenance of existing equipment.  During the year ended December 31, 2013, we made capital expenditures of approximately $2,475,000, primarily to maintain existing equipment.  During the year ended December 31, 2012, capital expenditures of approximately $57,108,000 were used to acquire, maintain, and replace seismic equipment and vehicles. Major purchases in 2012 included our fourth GSR System with 7,200 channels, our fifth GSR System with 7,000 channels, our sixth GSR System with 13,000 channels, some of which were added to existing systems, an 8,000 station 3-channel GSX wireless recording system, and seven new INOVA vibration vehicles.  These major investments should continue to bring us the benefits of these new technologies.

Customers

Our customers are major and independent oil and natural gas exploration and development companies. The services we provide to our customers vary according to the size and needs of each customer.  Our services are marketed by supervisory and executive personnel who contact customers to determine their needs and respond to customer inquiries regarding the availability of crews. Contacts are based principally upon professional relationships developed over a number of years.

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During 2014, our two largest customers accounted for approximately 18% and 11% of revenues, respectively.  During 2013, our largest customer accounted for approximately 12% of revenues.  During 2012, our largest customer accounted for approximately 16% of revenues.  At December 31, 2014 and December 31, 2013, our backlog was approximately $37 million and $52 million, respectively.  We filled our 2013 backlog during fiscal 2014, and anticipate filling our 2014 backlog during fiscal year 2015.  Due to our backlog and the Merger, we would not expect the loss of any single customer would have a material adverse effect on the operations of the newly combined company.

In order to avoid potential conflicts of interest with our customers, we do not participate in oil and natural gas ventures. The results of a seismic survey conducted for a customer belong to that customer. All of our customers’ information is maintained in strictest confidence.

Domestic and Foreign Operations

We derived our revenue from domestic and foreign sources.  Total revenues for the year ended December 31, 2014 were approximately $118,848,000, of which $68,371,000 were earned in the United States and $50,477,000 were earned in Canada.  Total revenues for the year ended December 31, 2013 were approximately $134,535,000, of which $86,519,000 were earned in the United States and $48,016,000 were earned in Canada.  Total revenues for the year ended December 31, 2012 were approximately $196,317,000, of which $124,856,000 were earned in the United States and $71,461,000 were earned in Canada.

Long-lived assets as of December 31, 2014 were approximately $48,792,000, with $18,621,000 located in the United States and $30,171,000 located in Canada.  Long-lived assets as of December 31, 2013 were approximately $63,107,000, with $20,148,000 located in the United States and $42,959,000 located in Canada.  Long-lived assets as of December 31, 2012 were approximately $89,386,000, with $32,390,000 located in the United States and $56,996,000 located in Canada.

Contracts

Our contracts are obtained either through competitive bidding or as a result of customer negotiations. Our services are conducted under general service agreements for seismic data acquisition services which define certain obligations for us and for our customers. A supplemental agreement setting forth the terms of a specific project, which may be canceled by either party upon 30 days’ advance written 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.

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 CGG (which recently sold its North American onshore seismic contract acquisition business to Geokinetics) and SAE. Our other major competitors include Geokinetics, Global Geophysical, Tesla, Breckenridge, Paragon and LoneStar. 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 crews.

Employees

As of December 31, 2014, we employed a total of 745 full-time employees, of which 39 consisted of management, sales, and administrative personnel with the remainder being crew and crew support personnel.  We believe our relationship with our employees to be satisfactory.

Operating Risks and Insurance

Our business is subject to the hazards inherent in conducting seismic data acquisition activities in hostile environments with dangerous machinery, and in some instances explosives. These activities can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment, and marine life, and suspension of operations.

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 by the indemnification provisions in our general service agreements to the extent that the damage is due to our negligence or intentional misconduct.

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We do not carry insurance against certain risks that we could experience such as business interruption resulting from equipment maintenance or weather delays. We obtain insurance against certain property and personal casualty risks and other risks when such insurance is available and when our management considers it advisable to do so. As of December 31, 2014, our insurance coverage consists of employers’ liability with limits of $1,000,000 per accident and $2,000,000 in the aggregate, commercial general liability of $1,000,000 per accident and $2,000,000 in the aggregate, pollution liability of $1,000,000 per accident and $2,000,000 in the aggregate, automobile liability with a $1,000,000 combined single limit, and a $20,000,000 umbrella policy. Our general service agreements require us to have specific amounts of insurance.  Management believes that the Company’s insurance coverage is adequate.  There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us.

We may incur losses.

Legacy TGC reported net loss of approximately $9,528,000 for the year ended December 31, 2014, compared to a net loss of approximately $6,316,000 for the year ended December 31, 2013, and net income of approximately $15,672,000 for the year ended December 31, 2012. Additionally, Legacy Dawson reported a net loss of approximately $12,620,000 for its fiscal year ended September 30, 2014, compared to a net income of approximately $10,480,000 and $11,113,000 for its fiscal years ended September 30, 2013 and 2012, respectively. Legacy TGC also reported net income for 2011, net loss for 2010 and net income for 2009 and 2008, and Legacy Dawson reported net loss for its fiscal years 2011 and 2010 and net income for its fiscal years 2009 and 2008.

Our ability to be profitable in the future will depend on many factors beyond our control, but primarily on the level of demand for land-based seismic data acquisition services by oil and natural gas exploration and development companies.  Even if we do achieve profitability, we may not be able to sustain or increase profitability on a quarterly or annual basis.

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

Our revenues, operating results, and profitability 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 customer 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 continued to be volatile during the year ended December 31, 2014, and have resulted in significant demand fluctuations 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 for the second and third calendar quarters of each year. The demand for our services will 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, EBITDA margin, and profitability from quarter-to-quarter, which these factors render 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 face intense competition in our business from companies with greater financial resources.

The seismic data acquisition services industry is a highly competitive business in the continental U.S. and Canada.  Our competitors include companies with financial resources that are significantly greater than our own as well as companies of comparable and smaller size. In addition, 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 U.S. market and compete with us.

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. 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 fiscal period.

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 is 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, or 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.

We are subject to Canadian foreign currency exchange rate risk.

We conduct business in Canada which subjects us to foreign currency exchange rate risk.  Our results of operations and our cash flows could be impacted by changes in foreign currency exchange rates.

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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 rather rapidly, 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-less 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 with cash generated from operations, cash reserves and borrowings from commercial banks. Recently, we have funded some of our capital expenditures through equipment term loans and capital 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. Our strategy had been to upgrade our seismic data acquisition equipment on a regular basis to maintain our competitive position, however, Legacy TGC has had a maintenance capital expenditures policy in place since 2013.  We are in a capital intensive industry and have limitations on our ability to obtain the financing necessary to enable us to purchase state-of-the-art equipment. Certain of our competitors may be able to purchase newer equipment when we may not be able to do so.

We rely on a limited number of key suppliers for specific seismic services and equipment.

We depend on a limited number of third parties to supply us with specific seismic services and equipment. From time to time, increased demand for seismic data acquisition services has decreased the available supply of new seismic equipment, resulting in extended delivery dates on orders of new equipment. Any delay in obtaining equipment could delay our deployment of additional crews and restrict the productivity of existing crews, adversely affecting our business and results of operation. 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.

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 the delay caused by the inclement weather.

We are dependent on our management team and key employees, and the loss of any of them could harm our business.

We have limited management depth. The result of the loss, whether by death, departure or illness, of our President and Chief Executive Officer or other senior executives could have a material adverse effect on the ability of management to continue operations at the same level of efficiency.

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

We perform ongoing credit evaluations of our customers’ financial conditions and, generally, require no collateral from our customers. It is possible that one or more of our clients will become financially distressed, 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 may also increase our overall exposure to these credit risks. A default in payment from one of our large customers could have a material adverse effect on our operating revenues for the period involved.

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Certain of our core assets are pledged as collateral for short term notes and other obligations that require large monthly payments.

Certain assets that are critical to Legacy TGC’s operations, including 7,200 channels of GSR equipment acquired in 2012, two GSX Systems with a total of 13,000 channels acquired in 2012, an 8,000 station GSX system acquired in 2012 and a 10,500 channel INOVA Hawk system purchased in 2014 are pledged as collateral to commercial banks and could be subject to foreclosure in the event that we default on our indebtedness having 36 to 60 month terms.  As of December 31, 2014, Legacy TGC had debt obligations covering the purchase of this equipment that require monthly payments between approximately $128,000 and $216,000.  These debt obligations mature at various dates ranging from June of 2015 to September of 2017.  At December 31, 2014, Legacy Dawson had three outstanding notes payable to commercial banks in the aggregate amount of $8,577,000 that were secured by a security interest in its accounts receivable, equipment and related collateral. In addition, as of December 31, 2014, Legacy Dawson had obligations of $10,227,000 with respect to 112 vehicles leased under capital leases with Enterprise Fleet Management. Any decline in our operations could inhibit our ability to make these substantial monthly payments. In view of the short terms of these notes, a failure to make the monthly payments on these notes could cause our lenders to foreclose quickly on the assets securing these notes.  The foreclosure on certain of our core assets securing these notes could severely limit our ability to continue operations.

Our results of operations 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 expect to record intangibles associated with the combination of Legacy TGC and Legacy Dawson that we anticipate will be a significant 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, failure to realize the benefits of the Merger, or strategic decisions, could cause us to conclude that impairment indicators exist and that the asset values associated with our equipment or our intangibles, if any, must be impaired. If we are forced to impair our equipment or intangibles these noncash asset impairments could negatively affect our results of operations 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 would have on our results of operations.

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 risks 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.

We do not carry insurance against certain risks that could cause losses, including business interruption resulting from equipment maintenance or weather delays. See “Item 1. Business — Operating Risks and Insurance”.

Our general service agreements require us to have specific amounts of insurance. 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 acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a materially adverse effect on us.

We may be held liable for the actions of our subcontractors.

We often work as the general contractor on seismic data acquisition surveys and, consequently, engage a number of subcontractors to perform services and provide products. While we obtain contractual indemnification and insurance covering the acts of these subcontractors and require the subcontractors to obtain insurance for our benefit, we could be held liable for the actions of these subcontractors. In addition, subcontractors may cause injury to our personnel or damage to our property that is not fully covered by insurance.

We are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to maintain compliance with Section 404, or if the costs related to maintaining compliance are significant, our profitability, stock price, and 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 customers, 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.

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Industry Risks

We derive nearly all of our revenues from companies in the oil and natural gas exploration and development industry, a historically cyclical industry, 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, in part, on oil and natural gas prices. Significant fluctuations in oil and natural gas exploration activities and oil and natural gas prices have adversely affected the demand for our services and our results of operations in the past and would continue to do so if the level of such exploration activities and the prices for oil and natural gas were to decline in the future. In addition to the market prices of oil and natural gas, the willingness of our clients to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, including general economic conditions and the availability of credit. Any prolonged reduction in the overall level of 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:

·                   our revenues, cash flows, and profitability;

·                   our ability to maintain or increase our borrowing capacity;

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

·                   our ability to attract and retain skilled personnel whom we would need in the event of an upturn in the demand for our services.

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. 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:

·                   the cost of exploring for, producing, and delivering oil and natural gas;

·                   the discovery rate of new oil and natural gas reserves;

·                   the ability of oil and natural gas companies to raise capital and debt financing;

·                   actions by OPEC (the Organization of Petroleum Exporting Countries);

·                   political instability in the Middle East and other major oil and natural gas producing regions;

·                   economic conditions in the United States and elsewhere;

·                   domestic and foreign tax policy;

·                   domestic and foreign energy policy including the ever increasing emphasis on alternative sources of energy;

·                   weather conditions in the United States and elsewhere;

·                   the pace adopted by foreign governments for the exploration, development, and production of their national reserves;

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·                   the price of foreign imports of oil and natural gas;

·                   the overall supply and demand for oil and natural gas; and

·                   an economic downturn could adversely affect our revenues and cash flows if our customers and/or potential customers, become unable to pay, or must delay payment of, amounts owing to the Company because such customers are not successful in generating revenues or are precluded from securing necessary financing.

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

We and our customers may be adversely affected by an economic downturn.

An economic downturn could have a material adverse effect on our financial results and proposed plan of operations and could lead to further significant fluctuations in the demand for and pricing of oil and gas.  Reduced demand and pricing pressures could adversely affect the financial condition and results of operations of our customers and their ability to purchase our services.  We are not able to predict the timing, extent, and duration of the economic cycles in the markets in which we operate.

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.

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

Our operations are subject to a variety of federal, state, and 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 change legislation.  Canadian operations have been historically cyclical due to governmental restrictions on seismic acquisition during certain periods.  As a result, there is a risk that there will be a significant amount of unused equipment during those periods.  We are required to expend financial and managerial resources to comply with such laws and related permit requirements in our operations, and we anticipate that we will continue to be required to do so in the future. Although such expenditures historically have not been material to us, the fact that such laws or regulations change frequently makes it impossible for us to predict the cost or impact of such laws and regulations on our future operations. The adoption of laws and regulations that have the effect of reducing or curtailing exploration and development activities by energy companies could also adversely affect our operations by reducing the demand for our services.

Current and future legislation or regulation relating to climate change or hydraulic fracturing could negatively affect the exploration and production of oil and gas and adversely affect demand for our services.

In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (GHG) (including carbon dioxide and methane) may be contributing to global climate change, legislative and regulatory measures to address the concerns are in various phases of discussion or implementation at the national and state levels. At least one-half of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predict whether or when Congress may act on climate change legislation. The U.S. Environmental Protection Agency (the “EPA”) has promulgated a series of rulemakings and taken other actions that the EPA states will result in the regulation of GHG as “air pollutants” under the existing federal Clean Air Act. Furthermore, in 2010, EPA regulations became effective that require monitoring and reporting of GHG emissions on an annual basis, including extensive GHG monitoring and reporting requirements. While this new rule does not control GHG emission levels from any facilities, it will 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.

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This increasing governmental focus on global warming 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 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 prospects.

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. 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. If the FRAC Act or similar legislation in the next Congress 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, the EPA has 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 Representatives has commenced its own investigation into hydraulic fracturing practices. 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.

Risks Related To Our Common Stock

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 elsewhere in this Form 10-K, could cause the market price of our common stock to fall. The high and low sales prices of our common stock for the year ended December 31, 2014, were $22.35 and $5.79, respectively, as adjusted for our 1-for-3 Reverse Stock Split on February 11, 2015.

Our common stock is listed on the Nasdaq Global Select Market 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 2014 our daily trading volume was as low as 2,266 shares, as adjusted for our 1-for-3 Reverse Stock Split on February 11, 2015.  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.

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 restated certificate of formation, as amended, 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 board of 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.

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In addition, our board of directors 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.

If the price of our common stock falls below $5.00 per share, it may be considered a low-priced stock and may be subject to regulations that limit or restrict the potential market for the stock.

Our common stock may be considered a low priced stock pursuant to rules promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), if it falls below a price of $5.00 per share. Under these rules, broker-dealers participating in transactions in low priced securities must first deliver a risk disclosure document which describes the risks associated with such stock, the broker-dealer’s duties, the customer’s rights and remedies, and certain market and other information, and make a suitability determination approving the customer for low priced stock transactions based on the customer’s financial situation, investment experience and objectives. Broker-dealers must also disclose these restrictions in writing and provide monthly account statements to the customer, and obtain specific written consent of the customer. With these restrictions, the likely effect of designation as a low price stock would be to decrease the willingness of broker-dealers to make a market for our common stock, to decrease the liquidity of the stock and to increase the transaction costs of sales and purchase of such stocks compared to other securities. As of March 9, 2015, our common stock was quoted at a closing sales price of $5.04 per share and we cannot guarantee that our common stock will continue to trade at a price greater than $5.00 per share.

We paid our first cash dividend in 2012 but did not pay a cash dividend in 2013 or 2014 and may not pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock may provide a return to shareholders.

We paid our first cash dividend in December 2012 but did not pay a cash dividend in 2013 or 2014 and may not pay cash dividends on our common stock in the foreseeable future. While there are currently no restrictions prohibiting us from paying dividends to our shareholders, it is at the discretion of the board of directors whether we pay any cash dividends on our common stock and depends on our financial condition, results of operations, capital and legal requirements and other factors deemed relevant by the board of directors. On May 14, 2013 and May 14, 2012, we paid 5% stock dividends to our shareholders. No cash or stock dividends were declared or paid in 2014.