UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the Fiscal Year Ended September 30, 20112012

For the Transition Period From                     to

Commission File No. 001-34404

DAWSON GEOPHYSICAL COMPANY

508 West Wall, Suite 800, Midland, Texas 79701

(Principal Executive Office)

Telephone Number: 432-684-3000

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

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

None

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232 405 of the chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ        No  ¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨        No  þ

As of March 31, 2011,2012, the aggregate market value of Dawson Geophysical Company common stock, par value $0.33¹/₃ per share, held by non-affiliates (based upon the closing transaction price on Nasdaq) was approximately $334,408,885.$260,868,713.

On November 30, 2011,23, 2012, there were 7,910,8858,031,369 shares of Dawson Geophysical Company common stock, $0.33¹/₃ par value, outstanding.

As used in this report, the terms “we,” “our,” “us,” “Dawson” and the “Company” refer to Dawson Geophysical Company unless the context indicates otherwise.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement for its 20122013 Annual Meeting of Shareholders to be held on January 24, 201222, 2013 are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

DAWSON GEOPHYSICAL COMPANY

FORM 10-K

For the Fiscal Year Ended September 30, 20112012

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 the volatility of oil and natural gas prices, dependence upon energy industry spending, disruptions in the global economy, industry competition, delays, reductions or cancellations of service contracts, high fixed costs of operations, external factors affecting our crews such as weather interruptions and inability to obtain land access rights of way, reduced utilization, the type of contracts we enter into, crew productivity, limited number of customers, credit risk related to our customers, the availability of capital resources and operational disruptions. 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. 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 (the “Company”), a Texas corporation, is thea leading provider of onshore seismic data acquisition and processing services in the lower 48 states of the United States as measured by the number of active data acquisition crews.States. Founded in 1952, 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. During 2012, we entered the Canadian market by forming a new Canadian subsidiary. Over the past few years the focus of our efforts has shifted between natural gas and oil-based exploration projects. Natural gas projects were our primary focus until late 2008. Since that time, we have experienced a gradual shift in activity to oil exploration, which has accelerated as oil prices have increasedremained at a relatively high level in 2010, 2011 and 2011.2012 while natural gas prices have been relatively low during these periods. The majority of our crews are currently working in oil and liquids-rich producing basins. Our clients rely on seismic data to identify areas where subsurface conditions are favorable for the accumulation of hydrocarbons and to optimize the development and production of hydrocarbon reservoirs. During fiscal 2011,2012, substantially all of our revenues were derived from 3-D seismic data acquisition operations.

As of September 30, 2011,2012, we operated fourteen 3-D seismic data acquisition crews in the lower 48 states of the United States and a seismic data processing center. We market and supplement our services in the lower 48 from our headquarters in Midland, Texas and from additional offices in Houston, Denver, Oklahoma City and Pittsburgh. Our geophysicists perform data processing in our Midland, Houston and Oklahoma City offices, and our field operations are supported from our field office facility in Midland. We anticipate operating one data acquisition crew in Canada during the 2012-2013 winter season and do not expect these operations to have a

significant impact on our fiscal 2013 financial results. We will market and supplement our services in Canada from our office in Calgary, Canada. The results of a seismic survey conducted for a client belong to that client. We do not acquire seismic data for our own account nor do we participate in oil and gas ventures.

Demand for our data acquisition services is closely linked to oil and natural gas prices and the related level of spending for domestic exploration and development of oil and natural gas reserves. With the decline in the market prices for oil, and especially natural gas following the financial crisis of late 2008, we experienced a severe reduction in demand for our services beginning in early fiscal 2009. As a result, we reduced the number of active data acquisition crews we operated from sixteen in January 2009 to nine in October 2009. Since the middle of fiscal 2010, we have experienced stronger demand for our services and, as a result, we redeployed three data acquisition crews during fiscal 2010 and two data acquisition crews during fiscal 2011, bringing our current total to fourteen active crews.

Business Strategy

Our strategy is to maintain our leadership position in the U.S. onshore market.market and build our business in Canada. Key elements of our strategy include:

Business Description

Geophysical Services Overview. Our business consists of the acquisition and processing of seismic data to produce an image of the earth’s subsurface. The seismic method involves the recording of reflected acoustic or sonic waves from below the ground. In our operations, we introduce acoustic energy into the ground by using an acoustic energy source, usually large vibrating machines or through the detonation of dynamite. We then record the subsequent reflected energy, or echoes, with recording devices placed along the earth’s surface. These recording devices, or geophones, are placed on the ground individually or in groups connected together as a single recording channel. We generally use thousands of recording channels in our seismic surveys. Additional recording channels enhance the resolution of the seismic survey through increased imaging analysis and provide improved operational efficiencies for our clients.

We are able to collect seismic data using either 3-D or 2-D methods. During fiscal 2011,2012, substantially all of our revenues were derived from 3-D seismic data acquisition. Continued technological advances in seismic equipment and computing allow us to economically acquire and process data by placing large numbers of energy sources and recording channels over a broad area. The industry refers to the technique of broad distribution of energy sources and recording channels as the 3-D seismic method. The 3-D method creates an immense volume of seismic data which produces more precise images of the earth’s subsurface. Geophysicists use computers to interpret 3-D seismic data volumes, generate geologic models of the earth’s subsurface and identify subsurface features that are favorable for the accumulation of hydrocarbons. In contrast with 3-D methods, the 2-D method

involves the collection of seismic data in a linear fashion thus generating a single plane of subsurface seismic data. In recent years, the 2-D seismic method has been used as a regional evaluation tool in many of the limited access shale basins, in particular the Marcellus Shale in the Appalachian Basin, in which we operated one small channel count crew for halfa portion of fiscal 2011.2012.

3-D seismic data are used in the exploration for new reserves and enable oil and gas companies to better delineate existing fields and to augment their reservoir completion and 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, completion 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.

We are prepared to meet such demands with the implementation of improved techniques and evolving technology. In recent years, we have steadily increased the recording capacity of our crews by increasing channel count and the number of energy source units we operate. These increases allow for a greater density of both channels and energy sources in order to increase resolution and to improve operating efficiencies. We have also utilized multi-component recording equipment on several projects in an effort to gain more information to help our clients enhance their development of producing reservoirs. Multi-component recording involves the collection of different seismic waves, including shear waves, which aids in reservoir analysis such as fracture orientation and intensity in shales and more descriptive rock properties.

In recent years, we have experienced continued increases in recording channel capacity on a per crew or project basis. This increase in channel count 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. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and margins.

During fiscal 2011 and 2012, we purchased andor leased a significant number of cable-less recording channels. We have utilized this equipment as primarily stand-alone recording systems andbut on occasion in conjunction with our cable-based systems. As a result of the introduction of cable-less recording systems, we have realized increased crew efficiencies and increased revenue on projects using this equipment. We believe we will experience continued demand for cable-less recording systems in the future. As we have replaced cable-based recording equipment with cable-less equipment on certain crews, the cable-based recording equipment continues to be redeployed on existing crews as needed, including on the additional two crews fielded during the second quarter of fiscal 2011.

Data Acquisition. The seismic survey begins at the time a client requests that we formulate a proposal to acquire seismic data on its behalf. Geophysicists then assist the client in designing the specifications of the proposed 3-D survey. If the client accepts our proposal, permit agents, either our employees or contract agents, then obtain access rights of way from surface and mineral estate owners or lessees where the survey is to be conducted. From time to time, our clients undertake the permitting effort on their own prior to our submittal of a proposal.

Utilizing electronic surveying equipment, survey personnel, who are either our employees or contract companies, precisely locate the energy source and receiver positions from which the seismic data are collected. We use vibrator energy sources which are mounted on vehicles, the majority of which weigh 62,000 pounds each, to generate seismic energy, or we detonate dynamite charges placed in drill holes drilled below the earth’s surface. We use third-party contractors for the drilling of holes and the purchasing, handling and disposition of dynamite charges. We also use third-party helicopter services to move equipment in areas of difficult terrain in an effort to increase efficiency and reduce safety risk.

We currently own 157169 vibrator energy source units and over 161,000167,000 recording channels. We also currently own eighteen central recording systems. Of the eighteen recording systems we owned at September 30, 2011, three2012, six are OYOGeospace Technologies GSR cable-less recording systems, eight are ARAM ARIES cable-based recording systems sixand four are I/O System II RSR radio-based recording systems, and one is an I/O System II MRX cable-based recording system.systems. All of our systems record equivalent seismic information but vary in the manner by which seismic data are transferred to the central recording unit, as well as their operational flexibility and channel count expandability. From time to time, we utilize the cable-less OYOGeospace Technologies GSR system in conjunction with the ARAM ARIES cable system to increase the flexibility and recording capacity of the cable system.

At fiscal year end 2011,year-end 2012, we operated fourteen land-based seismic data acquisition crews. Each crew consists 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. Our equipment may be configured on our crews in various combinations to meet the demands of specific survey designs.

Of the fourteen data acquisition crews in operation at September 30, 2011, three2012, five used GSR recording systems, six used ARAM recording systems, and fivethree used RSR recording systems. All of our crews utilize either vibrator energy sources or dynamite energy sources. While the number of recording systems we own is in excess of the number needed to field our current level of data acquisition crews, we maintain the excess equipment to provide additional operational flexibility and to allow us to quickly deploy additional recording channels and energy source units as needed to respond to client demand and clients’ desire for improved data quality with greater subsurface images.

Client demand for more recording channels continues to increase as the industry strives for improved data quality with higher resolution subsurface images. We believe this trend will continue and that our ability to deploy a large number of recording channels and multiple energy source units provides us with the competitive advantages of operational versatility and increased productivity, in addition to improved data quality. In November 2011, we placed an order for twelve INOVA AHV IV 364 energy sources. The purchase of these additional energy sources will expand our energy source fleet to 169 by the end of the first quarter of fiscal year 2012.

Data Processing. We currently operate a computer center located in Midland, Texas and provide additional processing services through our Houston and Oklahoma City offices. Data processing primarily involves the enhancement of seismic data by improving reflected signal resolution, removing ambient noise and establishing proper spatial relationships of geological features. The data are then formatted in such a manner that computer graphic technology may be employed for examination and interpretation of the data by the user.

We continue to improve data processing efficiency and accuracy with the addition of improved processing software and high-speed computer technology. We purchase, develop or lease seismic data processing software under non-exclusive licensing arrangements.

Our computer center processes seismic data collected by our crews, as well as by other geophysical contractors. In addition, we reprocess previously recorded seismic data using current technology to enhance the data quality. Our processing contracts may be awarded jointly with, or independently from, data acquisition services. Data processing services comprise a small portion of our overall revenues.

Integrated Services. We maintain integrated in-house operations necessary to the development and completion of seismic surveys. Our experienced personnel have the capability to conduct or supervise the seismic survey design, permitting, surveying, data acquisition and processing functions for each seismic program. In-house support operations include health, safety, security and environmental programs as well as facilities for vehicle repair, vehicle paint and body repair, electronics repair, electrical engineering and software development. In addition, we perform line clearing operations, own temporary housing facilities and maintain a fleet of tractor trailers to transport our seismic acquisition equipment to our survey sites. We believe that maintaining as many of these functions as possible in-house contributes to better quality control and improved efficiency in our operations. Our clients are responsible for the interpretation of the seismic data we provide.

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 new assets and upgrading existing capital assets requires a commitment to capital spending. During fiscal 2011,2012, we invested $35,323,000 in$47,664,000 primarily on equipment and energy sources, including nineteen INOVA vibrator energy source units, 10,500 additional OYOGeospace Technologies GSR single-channel recording equipment in response to industry demand for more recording channelsunits, 3,000 stations of Geospace Technologies GSR three-channel units with three-component geophones and operational flexibility. In addition, we purchased ten INOVA AHV IV 364 vibrator units.additional conventional geophones. These purchases reflect our belief that the trend towards increased channel counts and energy sources in our industry will continue. Our Board of Directors has approved an initial $20,000,000$40,000,000 capital budget for fiscal 20122013 which will be used to purchase twelvenine INOVA AHV IV 364 vibrator energy sources units, increase channel count, make technical improvements in various phases of our operations and meet maintenance capital requirements. We believe that these additions will allow us to maintain our competitive position as we respond to client desire for higher resolution subsurface images.

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 fiscal 2011,2012, sales to our two largest clients,client, Chesapeake Energy Corporation, and Devon Energy, represented 27% and 24%21% of our revenue respectively.revenue. The remaining balance of our fiscal 20112012 revenue was derived from varied clients and none represented 10% or more of our fiscal 20112012 revenues. Although 51% of our fiscal 2011 revenues were derived from two clients, we believe that our relationship with these clients is well founded for continued contractual commitments for the foreseeable future in multiple producing basins across the lower 48 states. While still expected to be significant clients, we doWe anticipate that sales to Chesapeake and Devon will represent a smaller percentage of our overall revenues during fiscal 2012.2013.

We do not acquire data for our own account or for future sale, maintain multi-client data libraries or participate in oil and gas ventures. The results of a seismic survey 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.

Contracts

Our data acquisition services are conducted under master service contracts with our clients. These master service contracts define certain obligations for us and for our clients. A supplemental agreement setting forth the terms of a specific project, which may be cancelled by either party on short notice, is entered into for every data acquisition project. The supplemental agreements are either “turnkey” agreements that provide for a fixed fee to be paid to us for each unit of data acquired, or “term” agreements that provide for a fixed hourly, daily or monthly fee during the term of the project or projects. 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.

We operate under both turnkey and term supplemental agreements. The percentage of revenues derived from turnkey contracts has grown in the past few years from approximately half of our revenues in fiscal 2008 to in excess of three-quarters of our revenues in fiscal 2011.2012. Currently, most of our projects are operated under turnkey agreements. However, in the first quarter of fiscal 2013 we have observed an increase in inquiries and requests for term agreements.

Competition

The acquisition and processing of seismic data for the oil and natural gas industry is a highly competitive business in the United States. Contracts for such services generally are awarded on the basis of price quotations, crew experience and 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 competitors include companies with financial resources that are significantly greater than our own as well as companies of comparable and smaller size. Our primary competitors are CGG Veritas, Geokinetics Inc., Global Geophysical Services, Tidelands Geophysical Company and TESLA Exploration. 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 United States to enter the United States market and compete with us.

Employees

As of September 30, 2011,2012, we employed approximately 1,5071,452 persons, of which 1,3741,295 were engaged in providing energy sources and acquiring data. With respect to the remainder of our employees, nineten are engaged

in data processing, sixtysixty-eight are administrative personnel, fiftysixty-five are engaged in equipment maintenance and transport and fourteen are officers. Of the employees listed above, nine are geophysicists. Our employees are not represented by a labor union. We believe we have good relations with our employees.

Available Information

All of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed with or furnished to the Securities and Exchange Commission (“SEC”) on or after May 9, 1995 are available free of charge through our Internet Website, www.dawson3d.com, as soon as reasonably practical after we have electronically filed such material with, or furnished it to, the SEC. Information contained on our Internet Website is not incorporated by reference in this Annual Report on Form 10-K. In addition, the SEC maintains an Internet Website containing reports, proxy and information statements, and other information filed electronically at www.sec.gov. You may also read and copy this information, for a copying fee, at the SEC’s Public Reference Room at 100 F Street, N.E., Washington,  D.C. 20549. Please call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room.

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. Although the risks described below are the risks that we believe are material to our business, they are not the only risks that could affect our business. If any of the following events were to occur, our business, financial condition or results of operations could be materially adversely affected.

Our business depends on the level of exploration and production activities by the oil and natural gas industry. If oil and natural gas prices or the level of capital expenditures by oil and gas companies were to decline, demand for our services would decline and our results of operations would be adversely affected.

Demand for our services depends upon the level of spending by oil and natural gas companies for exploration, production, development and field management activities, which depend, in part, on oil and natural gas prices. Significant fluctuations in oil and natural gas exploration activities and commodity prices have adversely affected the demand for our services and our results of operations in years 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, our clients’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which our management has no control, including general economic conditions and the availability of credit. In particular, the market price of natural gas has been depressed for the past few years, and the demand for our services by

clients seeking natural gas has sharply declined over the same period. There can be no assurance that the current level of energy prices will be maintained or that exploration and development activities by our clients will be maintained at current levels. Any significant decline in exploration or production-related spending by our clients, whether due to a decrease in the market prices for oil and natural gas or otherwise, would have a material adverse effect on our results of operations. Additionally, increases in oil and gas prices may not increase demand for our products and services or otherwise have a positive effect on our results of operations or financial condition.

Factors affecting the prices of oil and natural gas and our clients’ desire to explore, develop and produce include:

The markets for oil and natural gas have historically been volatile and are likely to continue to be so in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

Weakness in the global economy during the past few years decreased demand for our seismic services, caused downward pressure on the prices we charge and affected our results of operations. Any renewed weakness in the global economy would likely adversely affect us in a similar manner.

Beginning in August 2008, disruptions and instability in the global financial markets and a worldwide recession forced many of our customers to abandon their development plans and to significantly reduce their capital expenditures during fiscal years 2009 and 2010. As a consequence, we experienced a severe reduction in demand for our services, downward pressure on the prices we charged our customers for our services, and our results of operations were adversely affected during these years. During this period, we also reduced the number of data acquisition crews we operated from sixteen in January 2009 to nine in October 2009, which reflects the decrease in demand for our services. Since the beginning of fiscal 2010, the financial crisis has eased, the price of oil has stabilized and demand for our services and our financial performance has improved. However, if economic conditions were to once again worsen, forcing our customers to reduce their capital expenditures, demand for our seismic services would decline and our results of operations would again be affected. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

We face intense competition in our business that could result in downward pricing pressure and the loss of market share.

The acquisition and processing of seismic data for the oil and natural gas industry is a highly competitive business in the United States. Some of our competitors have financial resources that are significantly greater than our own. Additionally, the seismic data acquisition business is extremely price competitive and has a history of periods in which seismic contractors bid jobs below cost and therefore adversely affect industry pricing. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. 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 United States to enter the United States market and compete with us. Competition from these and other competitors could result in downward pricing pressure and the loss of market share. See “Business — Competition.”

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 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

The high fixed costs of our operations could adversely affect our results of operations.

Our business has high fixed costs, which primarily consist of depreciation, maintenance expenses associated with our seismic data acquisition and processing equipment and certain crew costs. In periods of significant

downtimereductions in crew utilization or low crew productivity, these fixed costs do not decline as rapidly as our revenues. As a result, any significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays or other causes could adversely affect our results of operations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Liquidity and Capital Resources.”

Our revenues are subject to fluctuations that are beyond our control which could adversely affect our results of operations in any financial period.

Our operating results vary in material respects from quarter to quarter and will continue to do so in the future. Factors that cause variations include the timing of the receipt of contracts for data acquisition, timing of the commencement and completion of work under data acquisition contracts, land access permit and weather delays, seasonal factors such as holiday schedules, shorter winter days or agricultural or hunting seasons, and crew repositioning and crew utilization and productivity. Should one or more of our fourteen crews experience changes in timing due to one or more of these factors, our financial results could be subject to significant variations from period to period. Combined with our high fixed costs, these revenue fluctuations could also produce unexpected adverse results of operations in any fiscal period. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

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. Delays from adverse weather conditions have particularly affected our results of operations in past periods and are likely to affect our results in future periods. See “Business — Contracts.”

Our operations are subject to delays related to obtaining land access rights 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 have negatively affected our results of operations in past periods and may affect our results in future periods. See “Business — Data Acquisition.”

Our profitability is determined, in part, by the utilization level and productivity of our crews and the type of contracts we enter into 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 productivitylevel of utilization of our fourteen data acquisition crews, and the accuracyproductivity of our cost estimates.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 or in obtaining land access rights, 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 fiscal 2011,2012, most of our projects were 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. See “Business — Contracts.”

A limited number of customers operating in a single industry account for a significant portion of our revenues, and the loss of one of these customers could adversely affect our results of operations; we bear the risk if any of our clients become insolvent and fail to pay amounts owed to us, so any failure to pay by these clients could harm 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. Although our ten largest customers in fiscal 20112012 and 20102011 have varied, these customers accounted for approximately 78%67% and 70%78% of our total revenue for these respective periods. For the year ended September 30, 2011,2012, our two largest clientsclient represented approximately 27% and 24%21% of total revenues. If these clients,this client, 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. See “Business — Clients.”

We bear the credit risk if any of our clients become insolvent and fail to pay amounts owed to us. Although we perform ongoing credit evaluations of our customers’ financial conditions, we generally require no collateral from our customers. Some of our clients have experienced financial difficulties in the past and even filed bankruptcy while others may do so in the future. 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 customers may also increase our overall exposure to these credit risks. Our inability to collect our accounts receivable could have a materially adverse effect on our results of operations. In addition, from time to time, we experience contractual disputes with our

clients regarding the payment of invoices or other matters. While we seek to minimize these disputes and maintain good relations with our clients, we have in the past, and may in the future, experience disputes that could negatively affect our relationship with a client and consequently affect our results of operations in future periods.

We may be unable to attract and retain skilled and technically knowledgeable employees which could adversely affect our business and our growth.

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, and our failure to continue to attract and retain such individuals could adversely affect our ability to compete in the seismic services industry. We may experience significant competition for these skilled and technically knowledgeable personnel, particularly during periods of increased demand for seismic services. None of our employees are under employment contracts, and we have no key man insurance.

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 continue to increase, primarily due to the expansion of our infrastructure in response to client demand for 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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.

CertainSome 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.

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 and data processing technologies historically have progressed rather rapidly, and we expect this progression to continue. In order to remain competitive, we must continue to invest additional capital to maintain, upgrade and expand our seismic data acquisition capabilities. However, due to potential advances in technology and the related costs associated with such technological advances, we may not be able to fulfill this strategy, thus possibly affecting our ability to compete.

Our results of operations could be adversely affected by asset impairments.

We periodically review our portfolio of equipment for impairment. If we expect significant sustained decreases in oil and natural gas prices and reduced demand for our services, we may be required to write down the value of our equipment if the future cash flows anticipated to be generated from the related equipment falls below net book value. If we are forced to write down the value of our equipment, these noncash asset impairments could negatively affect our results of operations in the period in which they are recorded. See discussion of “Impairment of Long-Lived Assets” included in “Critical Accounting Policies.”

We operate under hazardous conditions that subject us to risk of damage to property or personnel injuries and may interrupt our business.

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 extreme weather and other dangerous conditions, including the use of dynamite as an energy source. These operations are subject to risks of injury to our personnel and third parties and damage to our 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. Our crews are mobile, and 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.

We may be subject to liability claims that are not covered by our master service agreements or by insurance.

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 in our master service agreements

to the extent that the damage was due to our or our subcontractors’ negligence, gross negligence or intentional misconduct.

Although we maintain what we believe is prudent insurance protection, we do not carry insurance against some of the risks that we could experience, including business interruptions resulting from equipment losses or weather delays, and the insurance which we do maintain might not be sufficient or adequate to cover all losses or liabilities. We obtain insurance against certain property and personal casualty and other risks when such insurance is available and when our management considers it advisable to do so. Such coverage is not always available or applicable and, when available, is subject to unilateral cancellation by the insuring companies on very short notice. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a materially adverse effect on our results of operations.

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.

Our industry is subject to governmental regulation which may adversely affect our future operations.

Our operations are subject to a variety of federal, state and local laws and regulations, including laws and regulations relating to protection of the environment and archeological sites. 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. 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

production activities by energy companies could also adversely affect our results of operations by reducing the demand for our services. In particular, laws and regulations concerning climate change or regulating hydraulic fracturing could adversely affect our operations and reduce demand for seismic 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-third 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.

This increasing governmental focus on global warming may result in new environmental laws or regulations that may negatively affect us, our suppliers and our customers. This could cause us to incur additional direct costs in complying with any new environmental regulations, as well as increased indirect costs resulting from our customers, 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 greenhouse gasesGHG may curtail production and demand for fossil fuels such as oil and gas in areas where our customers 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 enacted, the FRAC Act would amendor 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.

We are subject to Canadian foreign currency exchange rate risk.

We have recently begun to operate in Canada. Conducting business in Canada subjects us to foreign currency exchange rate risk. We do not hold or issue foreign currency forward contracts, option contracts or other derivative financial instruments for speculative purposes or to mitigate the currency exchange rate risk. If our operations in Canada are successful and the amount of business we do there grows, our results of operations and our cash flows could be impacted by changes in foreign currency exchange rates.

Certain provisions of our charter and bylaws and our shareholder rights plan may make it difficult for a third party to acquire us, even in situations that may be viewed as desirable by shareholders.

Our articles of incorporation and bylaws contain provisions that authorize the issuance of preferred stock and establish advance notice requirements for director nominations and actions to be taken at shareholder meetings. These provisions could discourage or impede a tender offer, proxy contest or other similar transaction involving control of the Company, even in situations that may be viewed as desirable by our shareholders. In addition, we have adopted a shareholder rights plan that would likely discourage a hostile attempt to acquire control of the Company.

Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our stock price.

If, in the future, we fail to maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act. Failure to achieve and maintain an effective internal control environment could have a material adverse effect on the price of our common stock.

Item 1B.    UNRESOLVED STAFF COMMENTS

None.

Item 2.    PROPERTIES

Our principal facilities are summarized in the table below.

We have operating leases for generaldomestic office space in Midland, Houston, Denver, Oklahoma City Lyon Township, Michigan and Pittsburgh.Pittsburgh and foreign office space in Calgary, Canada.

Our operations are limited to one industry segment andin the United States.States and Canada. 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.

For a discussion of certain contingencies affecting the Company, please refer to Note 13, “Commitments and Contingencies” to the Consolidated Financial Statements included herein, which is incorporated by reference herein.

Part II

Item 5.    MARKET FOR OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock trades on the Nasdaq Stock Market^® under the symbol “DWSN.” The table below represents the high and low sales prices per share for the period shown.

As of November 25, 2011,23, 2012, the market price for our common stock was $30.95$22.64 per share, and we had 149154 common stockholders of record, as reported by our transfer agent.

We have not paid cash dividends on our common stock since becoming a public company and have no plans to do so in the foreseeable future.

The following table summarizes certain information regarding securities authorized for issuance under our equity compensation plan as of September 30, 2011.2012. See information regarding material features of the plan in Note 7, “Stock-Based Compensation” to the Consolidated Financial Statements included herein.

Equity Compensation Plan Information

Performance Graph

The following graph compares the cumulative 5-year total return attained by shareholders on the Company’s common stock relative to the cumulative total returns of the S&P 500 index and the Value-Line Oilfield ServicesPHLX Oil Service Sector index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common stock and in each of the indexes on 9/30/2006,2007, and its relative performance is tracked through 9/30/2011.

Comparison of 5 Year Cumulative Total Return*

Among Dawson Geophysical Company, the S & P 500 Index

and the Value-Line Oilfield Services Index

2012.

*Item 6.

$100 invested on 9/30/06 in stock or index, including reinvestment of dividends. Fiscal year ended September 30.SELECTED FINANCIAL DATA

Copyright^© 2011 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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.”

The following discussion of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and notes to those statements included elsewhere in this Form 10-K. This discussion contains forward-looking statements that involve risks and uncertainties. Please see “Disclosure Regarding Forward-Looking Statements” and “Risk Factors” elsewhere in this Form 10-K.

Overview

We are thea leading provider of onshore seismic data acquisition services in the lower 48 states of the United States as measured by the number of active data acquisition crews.States. Substantially all of our revenues are derived from the seismic data acquisition services we provide to our clients, mainly domestic oil and natural gas companies. Demand for our services depends upon the level of spending by these companies for exploration, production, development and field management activities, which depends, in part, on oil and natural gas prices. Significant fluctuations in domestic oil and natural gas exploration activities and commodity prices have affected the demand for our services and our results of operations in years past, and such fluctuations continue to be the single most important factor affecting our business and results of operations.

Beginning in August 2008, the prices of oil and especially natural gas declined significantly from historic highs due to reduced demand from the global economic slowdown, and during 2009 many domestic oil and natural gas companies reduced their capital expenditures due to the decrease in market prices and disruptions in the credit markets. These factors led toAfter a severe reductioncontraction in demand for our services beginning at the end of 2008 and in our industry during 2009 as well as downward pressure on the prices we charged our customers for our services. In order to better align our crew capacity with reduced demand, we reduced the number of data acquisition crews we operated from sixteen in January 2009 to nine in October 2009. Duecontinuing into 2010 due to the reductions in the number of our active data acquisition crews and lower utilization rates for our remaining operating crews, we experienced a reduction in operating revenues and, to a lesser extent, in operating costs during calendar 2009 and into calendar 2010.

Beginning in the second quarter of fiscal 2010,global economic slowdown, we began to experience an increase in demand for our services, particularly in the oil and liquids-rich basins. Demand for our services has continued to strengthen through fiscal 2011. Our order book is currently at its highest level since late fiscal 2008.2011 and 2012. In response to this demand increase, we redeployed three seismic data acquisition crews in fiscal 2010 and two seismic data acquisition crews in fiscal 2011, bringing our current crew count to fourteen active crews. DuringOur order book is currently at its highest level since late fiscal 2011,2008 in terms of the client mix, size of projects and geographical diversity, and the majority of the projects are in oil and liquids-rich basins. Although our clients

may cancel, delay or alter their service contracts on short notice and we purchased 25,850 OYO GSR single-channel units, 2,000 OYO GSR four-channel units with three component geophonescontinue to remain subject to land access permit and ten INOVA AHV IV 364 vibrator energy source units. These additions allowed usweather delays, our current order book reflects commitment levels sufficient to deploymaintain operation of fourteen crews well into fiscal 2013. The majority of our crews are currently working in oil producing basins. However, in recent years, we have experienced periods in which the two additional crews in fiscal 2011 with state-of-the-art cable-less recording equipment.services we provided were primarily to clients seeking natural gas.

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, including factors such ascrews. Factors impacting productivity and utilization levels include crew downtime related to inclement weather, delays in acquiring land access permits, agricultural or hunting activity, holiday schedules, short winter days, crew repositioning or equipment failure, whether we enter into turnkey or term contracts with our clients, the number and size of crews and the number of recording channels per crew. To the extent we experience these factors our operating results may be affected from quarter to quarter. Consequently, our efforts to negotiate favorable contract terms in our supplemental service agreements, to mitigate permit access permit delays and to improve overall crew productivity may contribute to growth in our revenues. As demand for our services continues to be robust, we have beenwere able to negotiate more favorable contract terms during fiscal 20112012.

We experienced lower utilization rates during the third and fourth quarters of fiscal 2012 as our crews were affected by project preparation, weather delays, agricultural activity, land access permit issues and client delays. Our utilization rates were also affected by increasing crew efficiencies driven by improved crew processes and recent equipment purchases. In several instances during the second and third fiscal quarters of 2012, our data acquisition crews completed projects ahead of schedule and were idled as other projects were in preparatory and/or permitting phases. While these early project completions have a negative impact on utilization during a particular quarter, we believe the increasing efficiency of our crews may enable us to increase our overall capacity. We believe that the problems that led to lower utilization rates during the third and fourth quarters of fiscal 2012 have been resolved. We returned to full crew utilization during the fourth quarter of fiscal 2012, and such full utilization has continued into the beginningfirst quarter of fiscal 2012. In addition, we believe we will complete operations by the end of calendar 2011 on several legacy contracts contracted during fiscal 2010 with less favorable terms. During fiscal 2011,2013.

Currently, most of our client contracts wereare turnkey contracts. The percentage of revenues derived from turnkey contracts has grown in the past few years from approximately half of our revenues in fiscal 2008 to in excess of three-quarters of our revenues in fiscal 2011.2012. While turnkey contracts allow us to capitalize on improved crew productivity, we also bear more risks related to weather and crew downtime. We expect the percentage of turnkey contracts to remain high as we continue to expand our operations in the mid-continent, western and Rocky Mountainsouthwestern regions of the United States in which turnkey contracts are more common. Although our clients may cancel their service contracts on short notice, our current order book reflects commitment levels sufficient to maintain operationHowever, in the first quarter of our fourteen data acquisition crews well into fiscal 2012.2013 we have observed an increase in inquiries and requests for term contracts.

Over time, we have experienced continued increases in recording channel capacity on a per crew or project basis. This increase in channel count 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. We believe we will realize the benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and margins.

Reimbursable third-party charges related to our use of helicopter support services, specialized survey technologies and dynamite energy sources in areas with limited access are another important factor affecting our results. During fiscal 2011, the level of these third-party charges as a percentage of revenue was especially high, approaching 50% of revenue, mainly as a result of our continued operations in areas with limited access in the eastern United States. However, revenues associated with third-party charges declined as a percentage of revenue during fiscal 2012 as a result of such third-party charges returning to levels more consistent with our historical average. We expect that as we continue to expand our operations in the more open terrain of the mid-continent, western and southwestern regions of the United States, the level of these third-party charges will continue to be generally within our historical range of 25% to 35% of revenue.

During fiscal 2011, we purchased 25,850 Geospace Technologies GSR single-channel units, 2,000 Geospace Technologies GSR four-channel units with three-component geophones and leased a significant number often INOVA AHV IV 364 vibrator energy source units. These additions allowed us to deploy the two additional crews added in fiscal 2011 with state-of-the-art cable-less recording channels.equipment. During the first quarter of fiscal 2012, we began operations on a large project in West Texas utilizing the FairfieldNodal ZLand cable-less recording system. We have utilized this equipment as stand-alonecompleted the FairfieldNodal ZLand project during the third quarter of fiscal 2012. The ZLand-equipped crew was redeployed in the late third quarter of fiscal 2012 equipped with an ARAM cable-based recording systems and in conjunction with our cable-based systems.system. As a result of the introduction of the cable-less recording systems, we have realized increased crew efficiencies and increased revenue on projects using this equipment. We believe we will experience continued demand for cable-less recording systems in the future. During fiscal 2012, we purchased an additional 10,500 Geospace Technologies GSR single-channel units, 3,000 stations of Geospace Technologies GSR three-channel units with three component geophones and nineteen INOVA AHV IV 364 vibrator energy source units. As we have replaced cable-based recording equipment with cable-less equipment on certain crews, the cable-based recording equipment continues to be redeployed on existing crews as needed, including on the additional two crews fielded during the second quarter of fiscal 2011. Of the fourteen crews currently in operation, five use Geospace Technologies GSR recording systems, six use ARAM cable-based recording systems, and three use I/O RSR recording systems.

During 2012, we entered into the Canadian market. This market is highly seasonal and operates primarily from late November through March, depending upon weather conditions. We anticipate operating one data acquisition crew in Canada during the 2012–2013 winter season, and do not expect these operations to have a significant impact on our fiscal 2013 financial results.

While the markets for oil and natural gas have been very volatile and are likely to continue to be so in the future, and we can make no assurances as to future levels of domestic exploration or commodity prices, we believe opportunities exist for us to enhance our market position by responding to our clients’ continuing desire for higher resolution subsurface images. If economic conditions were to weaken, our customers reduce their capital expenditures or there is a significant sustained drop in oil and natural gas prices, it would result in diminished demand for our seismic services, could cause continued downward pressure on the prices we charge and would affect our results of operations. The majority of our crews are currently working in oil producing basins. However, in recent years, we have experienced periods in which the services we provided were primarily to clients seeking natural gas.

Fiscal 20112012 Highlights

Results of Operations

Fiscal Year Ended September 30, 2012 versus Fiscal Year Ended September 30, 2011

Operating Revenues. Our operating revenues decreased 4% to $319,274,000 in fiscal 2012 from $333,279,000 in fiscal 2011. The revenue decrease in fiscal 2012 was primarily the result of a significant decrease in third-party charges and is not indicative of declining operations. Third-party charges decreased 29% in fiscal 2012 from fiscal 2011 Versusdue to continued operations in the more wide open terrain of the Western United States while fee revenue net of third-party charges for fiscal 2012 increased 13% from fiscal 2011. The increase in revenues net of third party charges is a result of increased utilization, production and more favorable contract terms in 2012 as compared to 2011.

Operating Costs. Our operating expenses decreased 11% to $258,970,000 in fiscal 2012 from $292,519,000 in fiscal 2011 primarily due to the decrease in reimbursed charges. As discussed above, third-party charges decreased 29% in fiscal 2012 from fiscal 2011. Operating expenses excluding third-party charges in fiscal 2012 increased 4% from fiscal 2011. This increase resulted primarily from increased field personnel and other expenses associated with higher utilization in 2012 as compared to 2011. The increase in revenues net of third-party charges of 13% in fiscal 2012 at the same time operating costs excluding third-party charges increased only 4%, resulted in an overall improvement in the Company’s margins during fiscal 2012. Improved turnkey rates, increased productivity, reduced third-party charges and reduced equipment rental and repair costs all contributed to this improvement in margins.

General and administrative expenses were 3.5% of revenues in fiscal 2012 as compared to 4.1% of revenues in fiscal 2011. General and administrative expenses decreased by $2,345,000 in fiscal 2012 as compared to fiscal 2011. The primary factor for the decrease in general and administrative expenses was the absence during fiscal 2012 of fiscal 2011 transaction costs of $3,866,000 associated with the terminated merger agreement with TGC. Without the effect of the 2011 transaction costs, general and administrative expense increased by $1,521,000. The increase in administrative expense was primarily due to increased employee costs to support expanded field operations and start-up costs associated with our Canadian operations.

We recognized $32,498,000 of depreciation expense in fiscal 2012 as compared to $30,536,000 in fiscal 2011. Depreciation expense increased 6.4% from fiscal 2011 to 2012 reflecting increased capital expenditures during fiscal 2011 and 2012. Our depreciation expense is expected to continue to increase in fiscal 2013 as a result of our significant capital expenditures in fiscal 2012.

Our total operating costs for fiscal 2012 were $302,673,000, a decrease of 10% from fiscal 2011 primarily due to the factors described above.

Income Taxes. Income tax expense was $5,403,000 for fiscal 2012 and $439,000 for fiscal 2011. The effective tax rates for the income tax provision for fiscal 2012 and 2011 were 32.7% and (15.6%), respectively. Our effective tax rate was reduced significantly in fiscal 2011 by transaction costs that had been treated as permanent, non-deductible expenses. In fiscal 2012, these costs became fully tax deductible upon the merger’s termination in October 2011 and were treated as a discrete event in the first quarter of fiscal 2012, which resulted in an income tax benefit. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as foreign operations, state and local taxes, non-deductible expenses, discrete items, expenses related to share-based compensation that were not expected to result in a tax deduction and changes in reserves for uncertain tax positions.

Fiscal Year Ended September 30, 2011 versus Fiscal Year Ended September 30, 2010

Operating Revenues. Our operating revenues increased 62% to $333,279,000 in fiscal 2011 from $205,272,000 in fiscal 2010. The revenue increase in fiscal 2011 was primarily the result of an increase in active crew count during fiscal 2011 and higher utilization rates of the existing crews. Revenues in fiscal 2011 continued to include high third-party charges related to the use of helicopter support services, specialized survey technologies and dynamite energy sources. Approximately one-half of the increase in revenues during 2011 was due to the increase in these third-party charges. The sustained high level of these charges is driven by our continued operations in areas with limited access in the Appalachian Basin, Oklahoma, East Texas and Arkansas. We believe these third-party charges, for which we are reimbursed by our clients, will decrease to a more historical level of between 25% and 35% of revenues as we expand our operations in the more wide open terrain of the Western United States.

Operating Costs. Our operating expenses increased 58% to $292,519,000 in fiscal 2011 from $185,588,000 in fiscal 2010 primarily due to increases in field personnel and other expenses associated with operating the additional data acquisition crews put into service during fiscal 2010 and 2011. As discussed above, reimbursed charges have a similar impact on operating costs.

General and administrative expenses were 4.1% of revenues in fiscal 2011 as compared to 3.5% of revenues in fiscal 2010. General and administrative expenses increased by $6,419,000 in fiscal 2011 as compared to fiscal 2010. The primary factors for the increase in general and administrative expenses during fiscal 2011 were increased administrative costs, primarily related to employee costs as a result of our increased crew count and operational activity, and transaction costs of $3,866,000 associated with the terminated merger agreement with TGC Industries, Inc. (“TGC”).TGC. There was no termination fee associated with the termination of the TGC merger agreement.

We recognized $30,536,000 of depreciation expense in fiscal 2011 as compared to $27,126,000 in fiscal 2010. Depreciation expense increased 13% from fiscal 2010 to 2011 reflecting increased capital expenditures during fiscal 2010 and 2011. Our depreciation expense is expected to continue to increase in fiscal 2012 as a result of our significant capital expenditures in fiscal 2011.

Our total operating costs for fiscal 2011 were $336,605,000, an increase of 53% from fiscal 2010 primarily due to the factors described above.

Income Taxes. Income tax expense was $439,000 for fiscal 2011 as compared to income tax benefit of $4,638,000 for fiscal 2010. The effective tax rates for the income tax provision for fiscal 2011 and 2010 were (15.6%) and 33.2%, respectively. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, non-deductible expenses, expenses related to share-based compensation that were not expected to result in a tax deduction and changes in reserves for uncertain tax positions. Our fiscal 2011 effective tax rate was significantly impacted by the acquisition transaction costs incurred related to the terminated transaction with TGC. During fiscal 2011, we made the policy decision to treat the transaction costs as permanent non-deductible expenses for tax purposes. For further discussion of the terminated merger agreement and related policy decisions, see Note 16, “Subsequent Events” to the Financial Statements included herein.

Fiscal Year Ended September 30, 2010 Versus Fiscal Year Ended September 30, 2009Use of EBITDA (Non-GAAP measure)

Operating Revenues.We define EBITDA as net income (loss) plus interest expense, interest income, income taxes, depreciation and amortization expense. Our management uses EBITDA as a supplemental financial measure to assess:

We also understand that such data are used by investors to assess our performance. However, the second quarter of fiscal 2009 (four crews), third quarter of fiscal 2009 (two crews)term EBITDA is not defined under generally accepted accounting principles (“GAAP”), and first quarter EBITDA is not a measure

of 2010 (one crew)operating income, operating performance or liquidity presented in accordance with GAAP. When assessing our operating performance or liquidity, investors and others should not consider this data in isolation or as a substitute for net income (loss), a more competitive pricing environmentcash flow from operating activities or other cash flow data calculated in 2010 and substantially lower utilization rates of the remaining crews. Revenues in fiscal 2010 continuedaccordance with GAAP. In addition, our EBITDA may not be comparable to include high third-party charges related to the use of helicopter support services, specialized survey technologies and dynamite energy sources. The sustained level of these charges is drivenEBITDA or similarly titled measures utilized by our continued operations in areas with limited accessother companies since such other companies may not calculate EBITDA in the Appalachian Basin, East Texassame manner as us. Further, the results presented by EBITDA cannot be achieved without incurring the costs that the measure excludes: interest, taxes, depreciation and Arkansas. Weamortization.

The reconciliation of our EBITDA to our net income (loss) and net cash provided by operating activities, which are reimbursed for these charges by our clients.

Operating Costs. Our operating expenses decreased 4% to $185,588,000 in fiscal 2010 from $192,839,000 in fiscal 2009 primarily due to reductions in field personnel and other expenses associated with operating the data acquisition crews taken out of service during fiscal 2009 and 2010. As discussed above, reimbursed charges have a similar impact on operating costs.

General and administrative expenses were 3.5% of revenues in fiscal 2010 as compared to 3.2% of revenues in fiscal 2009. General and administrative expenses decreased by $725,000 in fiscal 2010 as compared to fiscal 2009. The primary factormost directly comparable GAAP financial measures, are provided in the decrease in general and administrative expenses during fiscal 2010 was a decrease in our bad debt expense.

We recognized $27,126,000 of depreciation expense in fiscal 2010 as compared to $26,160,000 in fiscal 2009. Depreciation expense increased a relatively modest 4% from fiscal 2009 to 2010 reflecting our limited maintenance capital expenditures in 2009.

Our total operating costs for fiscal 2010 were $219,845,000, a decrease of 3% from fiscal 2009 primarily due to the factors described above.tables below:

Taxes.Reconciliation of EBITDA to Net Income tax benefit was $4,638,000 for fiscal 2010 as compared(Loss)

Reconciliation of EBITDA to income tax expense of $7,493,000 for fiscal 2009. The effective tax rate for the income tax provision for fiscal 2010 and 2009 was 33.2% and 42.3%, respectively. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as state and local taxes, non-deductible expenses, expenses related to share-based compensation that were not expected to result in a tax deduction and changes in reserves for uncertain tax positions.Net Cash Provided by Operating Activities

Liquidity and Capital Resources

Introduction. Our principal sources of cash are amounts earned from the seismic data acquisition services we provide to our clients. Our principal uses of cash are the amounts used to provide these services, including expenses related to our operations and acquiring new equipment. Accordingly, our cash position depends (as do our revenues) on the level of demand for our services. Historically, cash generated from our operations along

with cash reserves and borrowings from commercial banks have been sufficient to fund our working capital requirements, and to some extent, our capital expenditures.

Cash Flows. Net cash provided by operating activities was $76,380,000 for fiscal 2012 and $16,951,000 for fiscal 2011 and $6,244,000 for fiscal 2010.2011. These amounts primarily reflect an increase in total revenues resultingand operating margins between periods. Our cash provided by operations was further positively impacted by cash collected from our expanded business which resulted in an increase in accounts receivable. Despite an increase in our outstanding receivables, ourprior periods. Our collection experience during the period expressed as an average number of days in accounts receivable has remained at approximately fifty-fivesixty over the last twelve months. Amounts in our trade accounts receivable that are over sixty days as of September 30, 2011 represent less than 15%2012 represents approximately 20% of our total trade accounts receivables, which is less thanconsistent with historical levels. We believe our allowance for doubtful accounts of $155,000$250,000 at September 30, 20112012 is adequate to cover exposures related to our trade account balances.

Net cash used in investing activities was $48,580,000 in fiscal 2012 and $36,417,000 in fiscal 2011 and $13,365,000 in2011. In fiscal 2010. During fiscal2012, we funded our capital expenditures primarily from cash provided by operating activities of $76,380,000 as well as proceeds of $9,346,000 from the Second Term Note used to purchase Geospace Technologies GSR recording equipment. In 2011, we funded our capital expenditures primarily from $22,500,000 in cash generated from matured short-term investments and $16,427,000 in proceeds from the Term Note used to purchase OYOGeospace Technologies GSR recording equipment as well as $16,951,000 of cash provided by operating activities. In 2010, we used cash generated from matured short-term investments to fund capital expenditures. In fiscal 2012 and 2011, we invested excess funds of $4,500,000 and $2,500,000 respectively in certificates of deposit, and in fiscal 2010, we invested $14,964,000 in U.S. treasury instruments.deposit. In fiscal 2011, we collected proceeds from an insurance claim on our equipment burned in an October 2010 wildfire of $1,392,000.

Net cash provided by financing activities in fiscal 20112012 and fiscal 20102011 was $3,496,000 and $15,868,000, respectively. In fiscal 2012, our primary source of net cash provided by financing activities was $9,346,000 in proceeds from our Second Term Note that were used to purchase Geospace Technologies GSR recording equipment and $4,000, respectively.subsequent principal payments for both the Term Note and Second Term Note. In fiscal 2011, our primary source of net cash provided by financing activities were the proceeds and subsequent principal payments for the $16,427,000 Term Note described above. Net cash provided by financing activitieswe entered into in fiscal 2010 primarily represented proceeds from the exercise of stock options.order to purchase Geospace Technologies GSR recording equipment.

Capital Expenditures. For fiscal year 2011,2012, we made capital expenditures of $59,380,000,$47,664,000, primarily to purchase 2,000 OYO GSR four-channel units, 25,850 OYO10,500 Geospace Technologies GSR single-channel units, 3,000 Geospace Technologies GSR three-channel units, additional geophones, tennineteen INOVA AHV IV 364 vibrator energy sources units and meet necessary maintenance capital requirements. These purchases reflect our belief that the trend towards increased channel counts and energy sources in our industry will continue. Our Board of Directors has approved an initial fiscal 20122013 capital budget of $20,000,000,$40,000,000, which will be used, in part, to purchase twelvenine INOVA AHV IV 364 vibrator energy source units, andwhile the remainder will be used to increase channel count, make technical improvements in various phases of our operations and meet maintenance capital requirements. We believe that our fiscal 20112012 capital investments as well as our planned fiscal 20122013 capital investments will allow us to maintain our competitive position as we respond to client desire for higher resolution subsurface images.

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 equipment term loans and capital leases. We have also funded our capital expenditures and other financing needs from time to time through public equity offerings.

Our revolving line of credit loan agreement is with Western National Bank. The agreement was renewed June 2, 2011 under the same terms as the previous agreement and permits us to borrow, repay and reborrow, from time to time until June 2, 2013, up to $20.0 million based on the borrowing base calculation as defined in the agreement. Our obligations under this agreement are secured by a security interest in our accounts receivable, equipment and related collateral. Interest on the facility accrues at an annual rate equal to either the 30-day London Interbank Offered Rate (“LIBOR”), plus two and one-quarter percent, or the Prime Rate, minus three-

quartersthree-quarters percent, as we direct monthly, subject to an interest rate floor of 4%. Interest on the outstanding amount under the loan agreement is payable monthly. The loan agreement contains customary covenants for credit facilities of this type, including limitations on disposition of assets, mergers and reorganizations. We are also obligated to meet certain financial covenants under the loan agreement, including maintaining specified ratios with respect to cash flow coverage, current assets and liabilities and debt to tangible net worth. We were in compliance with all covenants including specificspecified ratios as of September 30, 20112012 and November 30, 2011December 5, 2012 and have the full line of credit available for borrowing. We have not utilized the revolving line of credit loan agreement during the fiscal years ended September 30, 20112012 or 2010.2011.

On June 24, 2011, we exercised our purchase option for certain OYO GSR recording equipment we had been leasing. In order to finance this purchase, we restated

We amended our credit loan agreement with Western National Bank on June 30, 2011 to add a new term loan note (“Term Note”) provision, which provided $16,427,000 in financing for the purchase of theGeospace Technologies GSR equipment. The Term Note is repayable over a period of 36 months at $485,444 per month plus any applicable interest. The Term Note bears interest at an annual rate equal to either the 30-day London Interbank Offered Rate (“LIBOR”)LIBOR, plus two and one-quarter percent, or the Prime Rate, minus three-quarters percent, as we direct monthly, subject to an interest rate floor of 4%, and otherwise has the same terms as our revolving loan, except that theline of credit. The Term Note is collateralized by the OYOa security interest in our accounts receivable, equipment and related collateral and matures with all outstanding balances due on June 30, 2014.

On May 11, 2012, we entered into a Multiple Advance Term Note (“Second Term Note”) under our credit loan agreement with Western National Bank. The Second Term Note allows us to borrow from time to time up to $15.0 million to purchase equipment. On July 5, 2012, we borrowed $9,346,000 under the Second Term Note to purchase Geospace Technologies GSR recording equipment. The outstanding principal under the Second Term Note will be amortized over 36 months. The Second Term Note bears interest at an annual rate equal to either the 30-day LIBOR, plus two and one-quarter percent, or the Prime Rate, minus three-quarters percent, as we direct monthly, subject to an interest rate floor of 3.75%, and otherwise has the same terms as our revolving line of credit. The Second Term Note is collateralized by a security interest in our accounts receivable, equipment and related collateral and matures with all outstanding balances due on May 2, 2015.

In the second quarter of fiscal 2012, we began leasing vehicles from Enterprise Fleet Management under capital leases. These capital lease obligations are payable in 36 to 60 monthly installments and mature between December 2014 and February 2017. At September 30, 2012, we had leased 42 vehicles under these capital leases.

The following table summarizes payments due in specific periods related to our contractual obligations with initial terms exceeding one year as of September 30, 2011.2012.

On March 31, 2009,In April 2012, we filed a shelf registration statement with the SEC covering the periodic offer and sale of up to $100.0$150.0 million in debt securities, preferred and common stock and warrants. The registration statement allows us to sell securities in one or more separate offerings with the size, price and terms to be determined at the time of sale. The terms of any securities offered would be described in a related prospectus to be filed separately with the SEC at the time of the offering. The filing of the shelf registration statement will enable us to act quickly if and when opportunities arise.

We believe that our capital resources and cash flow from operations are adequate to meet our current operational needs. We believe we will be able to finance our capital requirements through cash flowgenerated from operations, cash on hand, through borrowings under our revolving line of credit, or additional equipment term loans.loans and capital leases. However, our ability to satisfy our working capital requirements and fund future capital requirements will depend principally upon our future operating performance, which is subject to the risks inherent in our business, including the demand for our seismic services from clients.

Off-Balance Sheet Arrangements

As of September 30, 2011,2012, we had no off-balance sheet arrangements.

Effect of Inflation

We do not believe that inflation has had a material effect on our business, results of operations or financial condition during the past three fiscal years.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make certain assumptions and estimates that affect the reported amounts of assets and liabilities at

the date of our financial statements and the reported amounts of revenues and expenses during the reporting periods. Because of the use of assumptions and estimates inherent in the reporting process, actual results could differ from those estimates.

Allowance for Doubtful Accounts. We prepare our allowance for doubtful accounts receivable based on our review of past-due accounts, our past experience of historical write-offs and our current client base. While the collectability of outstanding client invoices is continually assessed, the inherent volatility of the energy industry’s business cycle can cause swift and unpredictable changes in the financial stability of our clients.

Property, Plant and Equipment. Our property, plant and equipment is capitalized at historical cost and depreciated over the useful life of the asset. Our estimation of this useful life is based on circumstances that exist in the seismic industry and information available at the time of the purchase of the asset. As circumstances change and new information becomes available, these estimates could change.

Depreciation is computed using the straight-line method. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is reflected in the results of operations for the period.

Impairment of Long-Lived Assets. We review long-lived assets for impairment when triggering events occur suggesting deterioration in the assets’ recoverability or fair value. Recognition of an impairment charge is required if future expected undiscounted net cash flows are insufficient to recover the carrying value of the assets and the fair value of the assets is below the carrying value of the assets. Our forecast of future cash flows used to perform impairment analysis includes estimates of future revenues and expenses based on our anticipated future results while considering anticipated future oil and gas prices, which is fundamental in assessing demand for our services. If the carrying amounts of the assets exceed the estimated expected undiscounted future cash flows, we measure the amount of possible impairment by comparing the carrying amount of the asset to its fair value.

Revenue Recognition. Our services are provided under cancelable service contracts. These contracts are either “turnkey” or “term” agreements. Under both types of agreements, we recognize revenues when revenue is realizable and services are performed. Services are defined as the commencement of data acquisition or processing operations. Revenues are considered realizable when earned according to the terms of 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. In the case of a cancelled service contract, we recognize revenue and bill our client for services performed up to the date of cancellation.

We also receive reimbursements for certain out-of-pocket expenses under the terms of our service contracts. We record amounts billed to clients in revenue at the gross amount including out-of-pocket expenses that are reimbursed by the client.

In some instances, we bill clients in advance of the services performed. In those cases, we recognize the liability as deferred revenue. As services are performed, those deferred revenue amounts are recognized as revenue.

When it becomes evident that the estimates of total costs to be incurred on a contract will exceed the total estimates of revenue to be earned, an estimated contract loss is recognized in the period in which the loss is identifiable.

Allowance for Doubtful Accounts.Stock-Based Compensation. We prepare our allowance for doubtful accounts receivable based on our review of past-due accounts, our past experience of historical write-offsmeasure all employee stock-based compensation awards, which include stock options and our current client base. While the collectibility of outstanding client invoices is continually assessed, the inherent volatility of the energy industry’s business cycle can cause swift and unpredictable changes in the financial stability of our clients.

Impairment of Long-Lived Assets. We review long-lived assets for impairment when triggering events occur suggesting deterioration in the assets’ recoverability or fair value. Recognition of an impairment charge is required if future expected undiscounted net cash flows are insufficient to recover the carrying value of the assets andrestricted stock, using the fair value method and recognize compensation cost, net of estimated forfeitures, in our financial statements. We record compensation expense as operating or general and administrative expense as appropriate in the Consolidated Statements of Operations on a straight-line basis over the vesting period of the assets is below the carrying value of the assets. Our forecast of future cash flows used to perform impairment analysis includes estimates of future revenues and expenses based on our anticipated future results while considering anticipated future oil and gas prices, which is fundamental in assessing demand for our services. If the carrying amounts of the assets exceed the estimated expected undiscounted future cash flows, we measure the amount of possible impairment by comparing the carrying amount of the asset to its fair value.related stock options or restricted stock awards.

Property, Plant and Equipment. Our property, plant and equipment is capitalized at historical cost and depreciated over the useful life of the asset. Our estimation of this useful life is based on circumstances that exist in the seismic industry and information available at the time of the purchase of the asset. As circumstances change and new information becomes available, these estimates could change.

Depreciation is computed using the straight-line method. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is reflected in the results of operations for the period.

Tax Accounting.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.

Stock-Based Compensation. We measure all employee stock-based compensation awards, which include stock options and restricted stock, using the fair value method and recognize compensation cost, net of forfeitures, in our financial statements. We record compensation expense as operating or general and administrative expense as appropriate in the Statements of Operations on a straight-line basis over the vesting period of the related stock options or restricted stock awards.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards,” to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles and enhances disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 will beThe enhanced disclosures and fair value measurement principles were effective in our second quarterfor us as of fiscal 2012 and will be applied prospectively. We are currently evaluating the impactJanuary 1, 2012. The adoption of ASU 2011-04 and believe the adoption willthis guidance did not have a material effectimpact on our financial statements.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” to require an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of equity. This update does not change what items are reported in other comprehensive income or the requirement to report reclassification of items from other comprehensive income to net income. However, in December 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” that deferred the specific requirement within ASU 2011-05 to present on the face of the financial statements items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive net income. Entities should continue to report reclassifications out of accumulated other comprehensive income using guidance in effect before ASU 2011-05 was issued. ASU 2011-05 will be effective in our first quarter of fiscal 2013, though earlier adoption is permitted. The update will be applied retrospectively upon adoption. Weadoption, and we believe the adoption will not have a material effect on our financial statements.

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 andof 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 do not currentlyDuring 2012, we began to conduct business internationally, so we are not generallyin Canada which may subject our results of operations and cash flow to foreign currency exchange rate risk.

Concentration andof 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. We believe that our allowance for doubtful accounts of $155,000$250,000 at September 30, 20112012 is adequate to cover exposures related to our trade account balances.

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.

Interest Rate Risk. We are exposed to the impact of interest rate changes on the outstanding indebtedness under our credit loan agreement, which has variable interest rates. Amounts drawn under the revolving line of credit and equipment Term Noteterm loans bear interest at variable rates based on the lower of the Prime Rate, minus three-quarters percent, or the 30-day LIBOR, plus a margin of two and one-quarter percent, subject to an interest rate floor of 4%. for the Term Note and the revolving line of credit and an interest rate floor of 3.75% for the Second Term Note. At September 30, 2011, we had a balance of $15,571,000 on2012, our equipmentinterest rate was 4% for the Term Note and no amounts were outstanding under the revolver.revolving line of credit and 3.75% for the Second Term Note.

We have cash in the bank which, at times, may exceed federally insured limits. Historically, we have not experienced any losses in such accounts. Recentaccounts; however, volatility in financial markets may impact our credit risk on cash and short-term investments. At September 30, 2011,2012, cash and cash equivalents totaled $26,077,000.$57,373,000.

The information required by this item appears on pages F-1 through F-22 hereof and are incorporated herein by reference.

None.

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive and principal financial officers, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President, Secretary and Chief Financial Officer concluded that, as of September 30, 2011,2012, our disclosure controls and procedures were effective, in all material respects, with regard to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, for information required to be disclosed by us in the reports that we file or submit under the Exchange Act. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer and our Executive Vice President, Secretary and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the

reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including our President and Chief Executive Officer and Executive Vice President, Secretary and Chief Financial Officer, we evaluated the effectiveness of our internal controls over financial reporting as of September 30, 20112012 using the criteria set forth inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that, as of September 30, 2011,2012, our internal control over financial reporting was effective. Our internal control over financial reporting as of September 30, 20112012 has been audited by KPMG LLP, the independent registered public accounting firm who also audited our financial statements. Their attestation report appears on page F-3.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended September 30, 20112012 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

None.

Part III

The information required by Item 10 is incorporated by reference to our definitive proxy statement for our Annual Meeting of Shareholders to be held on January 24, 2012,22, 2013, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2011.2012. Certain information with respect to our executive officers is set forth below. OurWe have a code of ethics (asas defined in Item 406 of Regulation S-K) was adopted by our Board of Directors on May 25, 2004.S-K. The Code of Business Conduct and Ethics applies to our directors, officers and employees, including our principal executive officer and principal financial and accounting officer. Our Code of Business Conduct and Ethics is posted on our website at http://www.dawson3d.com in the “Corporate Governance” area of the “Investor Relations” section. ChangesWe intend to and waivers granted with respectsatisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, ouror waiver from, a provision of the Code of Business Conduct and Ethics related tofor our senior financial officers, identified above, andincluding the Chief Executive Officer, if any, either by posting such information on our other executive officers and directors that we are required to disclose pursuant to applicable rules and regulationswebsite at http://www.dawson3d.com in the “Corporate Governance” area of the SEC, will also be posted on our website.“Investor Relations” section or by filing a Form 8-K.

Executive Officers of the Registrant

Set forth below are the names, ages and positions of the Company’s executive officers.

The Board of Directors elects executive officers annually. Executive officers hold office until their successors are elected and have qualified.

Set forth below are descriptions of the principal occupations during at least the past five years of the Company’s executive officers.

L. Decker Dawson. Mr. Dawson founded the Company in 1952. He served as President of the Company until being elected as Chairman of the Board of Directors and Chief Executive Officer in January 2001. In January 2006, Mr. Dawson was reelected as Chairman of the Board of Directors and retired as Chief Executive Officer of the Company. Prior to 1952, Mr. Dawson was a geophysicist with Republic Exploration Company, a geophysical company. Mr. Dawson served as President of the Society of Exploration Geophysicists (1989-1990), received its Enterprise Award in 1997 and was awarded honorary membership in 2002. He was Chairman of the Board of Directors of the International Association of Geophysical Contractors in 1981 and is an honorary life member of such association. He was inducted into the Permian Basin Petroleum Museum’s Hall of Fame in 1997.

Stephen C. Jumper. Mr. Jumper, a geophysicist, joined the Company in 1985, was elected Vice President of Technical Services in September 1997 and was subsequently elected President, Chief Operating Officer and Director in January 2001. In January 2006, Mr. Jumper was elected President, Chief Executive Officer and Director. Prior to 1997, Mr. Jumper served the Company as manager of technical services with an emphasis on 3-D processing. Mr. Jumper has served the Permian Basin Geophysical Society as Second Vice President, (1991), First Vice President (1992) and as President (1993).President.

C. Ray Tobias. Mr. Tobias joined the Company in 1990 and was elected Vice President in September 1997 and Executive Vice President and Director in January 2001. In January 2006, Mr. Tobias was elected Executive Vice President and Chief Operating Officer. Mr. Tobias supervises client relationships and survey cost quotations to clients. He has served on the Board of Directors of the International Association of Geophysical Contractors and served as President of the Permian Basin Geophysical Society. Prior to joining the Company, Mr. Tobias was employed by Geo-Search Corporation where he was an operations supervisor.

Christina W. Hagan. Ms. Hagan joined the Company in 1988 and was elected Chief Financial Officer and Vice President in 1997 and Senior Vice President, Secretary and Chief Financial Officer in January 2003. In January 2004, Ms. Hagan was elected as Executive Vice President, Secretary and Chief Financial Officer. Prior thereto, Ms. Hagan served the Company as Controller and Treasurer. Ms. Hagan is a certified public accountant.

HowellJames W. Pardue.Thomas. Mr. PardueThomas joined the Company in 19762002 as Vice President of Data Processing and Director.Chief Geophysicist. Mr. PardueThomas was elected Executive Vice President of Data Processing in 1997.March 2007 and Chief Technical Officer in January 2012. Prior to joining the Company, Mr. PardueThomas was employed in data processing for 1721 years by Geosource, Inc. and its predecessor geophysical company.Phillips Petroleum Company.

K.S. Forsdick. Mr. Forsdick joined the Company in 1993, was elected Vice President in January 2001 and was subsequently elected Senior Vice President in March 2009. Mr. Forsdick is responsible for soliciting, designing and bidding seismic surveys for prospective clients. Prior to joining the Company, Mr. Forsdick was employed by Grant Geophysical Company and Western Geophysical Company and was responsible for marketing and managing land and marine seismic surveys for domestic and international operations. He has served on the Governmental Affairs Committee of the International Association of Geophysical Contractors.

The information required by Item 11 is incorporated by reference to our definitive proxy statement for our Annual Meeting of Shareholders to be held on January 24, 2012,22, 2013, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2011.