Edgar Filing: DAWSON GEOPHYSICAL CO

10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended September 30, 2013

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From to

Commission File No. 001-34404

DAWSON GEOPHYSICAL COMPANY

Texas

75-0970548

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

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:


Title of Each Class		Name of Exchange on Which Registered
Common Stock, $0.33 and ¹/₃ par value		The NASDAQ Stock Market

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):


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

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, 2013, 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 $235,459,000.

On November 22, 2013, there were 8,063,208 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 2014 Annual Meeting of Shareholders to be held on January 21, 2014 are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS


		Page
PART I
Item 1.	Business		2
Item 1A.	Risk Factors		7
Item 1B.	Unresolved Staff Comments		14
Item 2.	Properties		14
Item 3.	Legal Proceedings		14
PART II
Item 5.	Market for Our Common Equity and Related Stockholder Matters		15
Item 6.	Selected Financial Data		17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		27
Item 8.	Financial Statements and Supplementary Data		28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		28
Item 9A.	Controls and Procedures		28
Item 9B.	Other Information		29
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		30
Item 11.	Executive Compensation		31
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		31
Item 13.	Certain Relationships and Related Transactions and Director Independence		31
Item 14.	Principal Accounting Fees and Services		31
PART IV
Item 15.	Exhibits and Financial Statement Schedules		32
Signatures			33
Index to Financial Statements			F-1
Index to Exhibits

DAWSON GEOPHYSICAL COMPANY

FORM 10-K

For the Fiscal Year Ended September 30, 2013

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, industry competition, delays, reductions or cancellations of service contracts, reduced utilization, crew productivity, the type of contracts we enter into, external factors affecting our crews such as weather interruptions and inability to obtain land access rights of way, high fixed costs of our operations and our high capital requirements, limited number of clients, credit risk related to our clients, 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 a leading provider of onshore seismic data acquisition and processing services in the lower 48 states of the United 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 that began operations during the 2012-2013 winter season. Over the past few years, the focus of our efforts has shifted between natural gas and oil-based exploration projects. As a result, we have experienced a gradual shift in activity to oil exploration, which has accelerated as oil prices have remained at relatively high levels. 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 2013, substantially all of our revenues were derived from 3-D seismic data acquisition operations.

During fiscal 2013, we operated up to fourteen 3-D seismic data acquisition crews in the lower 48 states of the United States, one seismic data acquisition crew during the Canadian winter season and one 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 market and supplement our services in Canada from our office in Calgary, Alberta. 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 exploration and development of oil and natural gas reserves. In the past when the market prices for oil and natural gas have declined, we have experienced a severe reduction in demand for our services and as a result, we have reduced the number of active data acquisition crews we operate. During fiscal 2013, we mostly operated fourteen data acquisition crews, except in the last fiscal quarter of 2013 when we operated eight data acquisition crews.

Business Strategy

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

•

Attracting and retaining skilled and experienced personnel for our data acquisition and processing operations;

•

Providing integrated in-house services necessary in each phase of seismic data acquisition and processing, including project design, land access permitting, surveying and related support functions as well as maintaining our in-house health, safety, security and environmental programs;

•

Maintaining the focus of our operations on the North American onshore seismic market with a primary focus on the lower 48 United States;

•

Continuing to operate with conservative financial discipline;

•

Updating our capabilities to incorporate advances in geophysical and supporting technologies; and

•

Acquiring equipment to expand the recording channel capacity on our existing crews and equipping additional crews as market conditions dictate.

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 2013, 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 the 3-D method, the 2-D method involves the collection of seismic data in a linear fashion, thus generating a single plane of subsurface seismic data. 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 a portion of fiscal 2013.

3-D seismic data are used by our clients to explore for new reserves to better delineate existing oil and gas 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 2012 and 2013, we purchased or leased a significant number of cable-less recording channels. We have utilized this equipment as primarily stand-alone recording systems but 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 deployed on existing crews.

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 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 165 vibrator energy source units and over 159,000 recording channels. We also own eighteen central recording systems. Of the eighteen recording systems we owned at September 30, 2013, seven are Geospace Technologies GSR cable-less recording systems, eight are ARAM ARIES cable-based recording systems, one is a Wireless Seismic RT System 2 system and two are I/O System II RSR radio-based recording 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 Geospace Technologies GSR system in conjunction with the ARAM ARIES cable system to increase the flexibility and recording capacity of the cable system.

During fiscal 2013, we operated between eight and 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.

All of our crews utilize either vibrator energy sources or dynamite energy sources. While the number of recording systems we own may exceed the number utilized in the field at any given time, we maintain the excess equipment to provide additional operational flexibility and to allow us to quickly deploy additional recording channels and energy source units as needed to respond to client demand and 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.

During fiscal 2012, we began providing surface-recorded microseismic services utilizing equipment we currently own. Microseismic monitoring is used by clients who use hydraulic fracturing to extract hydrocarbon deposits to monitor their hydraulic fracturing operations.

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. Our clients are responsible for the interpretation of the seismic data we provide.

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 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.

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 2013, we invested $50,069,000 primarily on equipment and energy sources, including ten INOVA AHV IV 364 vibrator energy source units, 12,000 single-channel Geospace Technologies GSX units, 1,000 three-channel Geospace Technologies GSX units, 225 four-channel Geospace Technologies GSR units, for a total increase of 15,900 in Geospace

Technologies cable-less recording channels. In addition, we invested in 7,000 ARAM ARIES recording channels, 2,500 channels of Wireless Seismic RT System 2, additional conventional geophones, and vehicles to improve our fleet. 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 $35,000,000 capital budget for fiscal 2014 which will be used to purchase additional 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 2013, sales to two clients each represented more than 10% of our fiscal 2013 revenue and together represented 36% of our revenue. The remaining balance of our fiscal 2013 revenue was derived from varied clients and none represented 10% or more of our fiscal 2013 revenues. We anticipate that sales to these two clients will represent a smaller percentage of our overall revenues during fiscal 2014. We believe we are not dependent on any one client as our clients that have represented over 10% of our revenues between fiscal 2011 and 2013 have changed over time, as evidenced by the table in Note 12, “Major Clients” to the Consolidated Financial Statements included herein.

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. Currently, most of our projects are operated under turnkey agreements, which constituted approximately three-quarters of our revenues in fiscal 2013.

Competition

The acquisition and processing of seismic data for the oil and natural gas industry is a highly competitive business in the United States and Canada. 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, 2013, we employed approximately 1,252 persons, of which 1,077 were engaged in providing energy sources and acquiring data. With respect to the remainder of our employees, ten are engaged in data processing, seventy-nine are administrative personnel, seventy-two 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 several 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:

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the level of supply and demand for oil and natural gas;

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the level of prices, and expectations about future prices, for oil and natural gas;

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the ability of oil and gas producers to raise equity capital and debt financing;

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the worldwide political, military and economic conditions;

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the ability of the Organization of Petroleum Exporting Countries to set and maintain production levels and prices for oil;

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the rate of discovery of new oil and gas reserves and the decline of existing oil and gas reserves;

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

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the ability of exploration and production companies to generate funds or otherwise obtain capital for exploration, development and production operations;

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technological advances affecting energy exploration, production and consumption;

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government policies, including environmental regulations and tax policies, regarding the exploration for, production and development of oil and natural gas reserves and the use of fossil fuels and alternative energy sources; and

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weather conditions, including large-scale weather events such as hurricanes that affect oil and gas operations over a wide area or affect prices.

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.”

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 and Canada. 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 origination and completion of projects and when projects are awarded and contracted for is also uncertain. As a result, our order book as of any particular date may not be indicative of actual demand and revenues for any succeeding fiscal period. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

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 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.”

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

In fiscal 2013, 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.”

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.”

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 reductions 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 — Liquidity and Capital Resources.”

A limited number of clients operating in a single industry account for a significant portion of our revenues, and the loss of one of these clients could adversely affect our results of operations; we 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 clients in fiscal 2013 and 2012 have varied, these clients accounted for approximately 72% and 67% of our total revenue for these respective periods. For the year ended September 30, 2013, our two largest clients represented approximately 36% of total revenues. If these clients, or any of our other significant clients, were to terminate their contracts or fail to contract for our services in the future because they are acquired, alter their exploration or development strategy, experience financial difficulties or for any other reason, our results of operations could be adversely affected. 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 clients’ financial conditions, we generally require no collateral from our clients. 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 clients may also increase our overall exposure to these credit risks. Our inability to collect our accounts receivable could have a material 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. A limited number 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 remain high, primarily due to the expansion of our infrastructure in response to client demand for cable-less recording systems and more recording channels, which has increased as the industry strives for improved data quality with greater subsurface resolution images. Our sources of working capital are limited. We have historically funded our working capital requirements with cash generated from operations, cash reserves and borrowings from commercial banks. Recently, we have funded some of our capital expenditures through equipment term loans and capital leases. In the past, we have also funded our capital expenditures and other financing needs through public

equity offerings. If we were to expand our operations at a rate exceeding operating cash flow, if current demand or pricing of geophysical services were to decrease substantially or if technical advances or competitive pressures required us to acquire new equipment faster than our cash flow could sustain, additional financing could be required. If we were not able to obtain such financing or renew our existing revolving line of credit when needed, our failure could have a negative impact on our ability to pursue expansion and maintain our competitive advantage. 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.

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

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-half of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predict whether or when Congress may act on climate change legislation. The U.S. Environmental Protection Agency (the “EPA”) has promulgated a series of rulemakings and taken other actions that the EPA states will result in the regulation of GHG as “air pollutants” under the existing federal Clean Air Act. Furthermore, in 2010, EPA regulations became effective that require monitoring and reporting of GHG emissions on an annual basis, including extensive GHG monitoring and reporting requirements. While this new rule does not control GHG emission levels from any facilities, it will cause covered facilities to incur monitoring and reporting costs. Moreover, lawsuits have been filed seeking to require individual companies to reduce GHG emissions from their operations. These and other lawsuits relating to GHG emissions may result in decisions by state and federal courts and agencies that could impact our operations.

This increasing governmental focus on global warming may result in new environmental laws or regulations that may negatively affect us, our suppliers and our clients. This could cause us to incur additional direct costs in complying with any new environmental regulations, as well as increased indirect costs resulting from our clients, suppliers or both incurring additional compliance costs that get passed on to us. Moreover, passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict emissions of GHG may curtail production and demand for fossil fuels such as oil and gas in areas where our clients operate and thus adversely affect future demand for our services. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. At the federal level, a bill was introduced in Congress in March 2011 entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If the FRAC Act or similar legislation in the next Congress were enacted, the definition of “underground injection” in the SDWA would be amended to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In early 2010, the EPA indicated in a website posting that it intended to regulate hydraulic fracturing under the SDWA and require permitting for any well where hydraulic fracturing was conducted with the use of diesel as an additive. While industry groups have challenged the EPA’s website posting as improper rulemaking, the Agency’s position, if upheld, could require additional permitting. In addition, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. These legislative and regulatory initiatives imposing additional reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult or costly to complete natural gas wells. Shale gas cannot be economically produced without extensive fracturing. In the event such legislation is enacted, demand for our seismic acquisition services may be adversely affected.

We are subject to Canadian foreign currency exchange rate risk.

We have operations 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.


Location	Owned or Leased		Purpose	Building Area Square Feet
Midland, TX		Leased	Executive offices and data processing		29,960
Midland, TX		Owned	Field office		61,402
			Equipment fabrication facility
			Maintenance and repairs shop

We have operating leases for office space in Midland, Houston, Denver, Oklahoma City, Pittsburgh and Calgary, Alberta.

Our operations are limited to one industry segment in the United 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.


Quarter Ended	High		Low
December 31, 2011	$	40.18	$	21.57
March 31, 2012	$	40.76	$	32.92
June 30, 2012	$	34.57	$	20.29
September 30, 2012	$	26.31	$	20.20
December 31, 2012	$	26.64	$	25.54
March 31, 2013	$	30.24	$	29.56
June 30, 2013	$	38.03	$	36.80
September 30, 2013	$	32.70	$	32.08

As of November 22, 2013, the market price for our common stock was $30.94 per share, and we had 143 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 presently have no plans to do so. However, we regularly evaluate our dividend policy, taking into account such factors as our liquidity position and our near and long term capital requirements.

The following table summarizes certain information regarding securities authorized for issuance under our equity compensation plan as of September 30, 2013. 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


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options		Weighted-Average Exercise Price of Outstanding Options		Number of Securities Remaining Available for Future Issuance Under the Equity Compensation Plan (Excluding Securities Reflected in Column (a))
	(a)		(b)		(c)
Equity compensation plan approved by security holders		93,400	$	18.91		359,073
Equity compensation plans not approved by security holders		—		—		—

Total		93,400	$	18.91		359,073

PERFORMANCE GRAPH

The graph below matches Dawson Geophysical Company’s cumulative 5-Year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the PHLX Oil Service Sector index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends) from 9/30/2008 to 9/30/2013.

LOGO

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.”


Years Ended September 30,	2013		2012		2011			2010			2009
	(In thousands, except per share amounts)
Operating revenues	$	305,299	$	319,274	$	333,279		$	205,272		$	243,995
Net income (loss) (1)	$	10,480	$	11,113	$	(3,246	)	$	(9,352	)	$	10,222
Basic income (loss) per share attributable to common stock (2)	$	1.31	$	1.40	$	(0.42	)	$	(1.20	)	$	1.31
Weighted average equivalent common shares outstanding		7,880		7,842		7,810			7,777			7,807
Total assets	$	289,027	$	279,175	$	264,824		$	235,076		$	237,157
Revolving line of credit	$	—	$	—	$	—		$	—		$	—
Current maturities of notes payable and obligations under capital leases	$	9,258	$	9,131	$	5,290		$	—		$	—
Notes payable and obligations under capital leases less current maturities	$	3,697	$	11,179	$	10,281		$	—		$	—
Stockholders’ equity	$	213,060	$	200,949	$	188,163		$	190,225		$	198,379

(1)	Net loss for the year ended September 30, 2011 includes $3,866,000 of transaction costs associated with the terminated transaction with TGC Industries, Inc. (“TGC”).

(2)

The September 30, 2012 earnings per share calculation has been adjusted for the two-class method to reflect restricted shares that were not reflected as participating in the prior period. Basic earnings per share as previously reported for the year ended September 30, 2012 was $1.42. The impact on all prior period financial statements is deemed immaterial.

Item 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with 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 a leading provider of onshore seismic data acquisition services in the lower 48 states of the United States. During 2012, we entered the Canadian market by forming a new Canadian subsidiary, which operated during the 2012-2013 winter season. 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, the number of crews we operate 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.

During the majority of the 2011 and 2012 fiscal years we operated fourteen data acquisition crews. During fiscal 2013, we mostly operated fourteen data acquisition crews, except in the last fiscal quarter of 2013 when demand dictated we operate eight data acquisition crews. We have maintained a balanced order book in terms of the client mix and geographical diversity with the majority of the projects in oil and liquids-rich basins. 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.

While our revenues are mainly affected by the level of client demand for our services, our revenues are also affected by the pricing for our services that we negotiate with our clients and the productivity and utilization level of our data acquisition crews. Factors impacting productivity and utilization levels include 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 delays and to improve overall crew productivity may contribute to growth in our revenues. As demand for our services continues to be steady, we were able to negotiate more favorable contract terms during fiscal 2012 and 2013.

We experienced lower utilization rates during the fourth quarter of fiscal 2013 as our crews were affected by project preparation issues due to agricultural operation in key regions, weather delays, land access permit issues and softness in bid activity during the third fiscal quarter of 2013. Our utilization rates were also affected by increasing crew efficiencies driven by improved crew processes and recent equipment purchases. In several instances during the third fiscal quarter of 2013, our data acquisition crews completed projects ahead of schedule and were idled in the fourth fiscal quarter as other projects were in preparatory and/or permitting phases. These reduced utilization rates negatively impacted our financial results for the fourth fiscal quarter of 2013. While these early project completions have a negative impact on utilization during the quarter in which they occur, we believe the increasing efficiency of our crews may enable us to increase our overall capacity. As a result of the factors discussed above, we operated the equivalent of eight crews during the fourth fiscal quarter. The Company retained all key personnel required to redeploy existing crews during the period of low utilization. We believe that the problems that led to lower utilization rates during the fourth quarter of fiscal 2013 have been resolved and we returned to full utilization with the operation of twelve large channel crews and one small channel crew in the middle of the first fiscal quarter of 2014. Although our clients may cancel, delay or alter their service contracts on short notice and we continue to remain subject to land access permit and weather delays, our current order book reflects commitment levels sufficient to maintain operation of twelve large channel crews and one small channel crew into the middle of fiscal 2014.

Currently, most of our client contracts are turnkey contracts. The percentage of revenues derived from turnkey contracts has represented approximately three-quarters of our revenues in fiscal 2013 and for the past few years. 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 mid-continent, western and southwestern regions of the United States in which turnkey contracts are more common.

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, permit support services, specialized survey technologies and dynamite energy sources in areas with limited access are another important

factor affecting our results. Revenues associated with third-party charges declined as a percentage of revenue during fiscal 2012 and 2013 as a result of such third-party charges falling at or below 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 or below our historical range of 25% to 35% of revenue.

As a result of the introduction of the cable-less recording systems in 2012 and 2013, we have realized increased crew efficiencies and increased revenue on projects using these cable-less technologies. In response to the continued demand for cable-less recording systems, in the first quarter of fiscal 2013 we purchased 2,500 channels of Wireless Seismic RT System 2, 12,000 single-channel Geospace Technologies GSX units and 225 four-channel Geospace Technologies GSR units. In the fourth quarter of fiscal 2013, we purchased 1,000 three-channel Geospace Technologies GSX units, bringing our total fiscal 2013 investment in cable-less recording channels to 18,400. As we have replaced cable-based recording equipment with cable-less equipment on certain crews, the cable-based recording equipment continues to be deployed on existing crews as needed and we continue to phase out the older I/O RSR recording systems. Of the thirteen crews currently in operation, one uses a leased FairfieldNodal ZLand cable-less recording system, one uses the Wireless Seismic RT System 2, six use Geospace Technologies GSR recording systems and five use ARAM cable-based recording systems. During fiscal 2013, we continued a large project that will continue well into 2014 in southern New Mexico utilizing the FairfieldNodal ZLand cable-less recording system.

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. During fiscal 2013, Canadian operations did not significantly affect our fiscal 2013 financial results, although the Canadian operations did impact the year over year comparisons. While the 2012-2013 winter season was not as robust as anticipated, we completed our first multi-component 3-D survey in Canada, secured necessary industry safety audits and believe we performed at a high level of efficiency as a new entrant into the Canadian market. We anticipate operating one crew on two projects in Canada in the 2013-2014 winter season and do not expect these operations to have a significant impact on our fiscal 2014 financial results.

During fiscal 2012, we began providing surface-recorded microseismic services to some of our clients. Microseismic monitoring is used by clients who use hydraulic fracturing to extract hydrocarbon deposits to monitor their hydraulic fracturing operations. We completed several projects in fiscal 2013 and believe our microseismic business will continue to provide growth opportunities. These operations did not have a significant impact on our fiscal 2013 financial results, nor do we expect these operations to significantly impact our fiscal 2014 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 clients 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 downward pressure on the prices we charge and would affect our results of operations.

Fiscal 2013 Highlights

•

EBITDA for the year-ended September 30, 2013 increased to $57,262,000 compared to $49,615,000 for the same period of fiscal 2012, an increase of 15 percent;

•

Income from operations for fiscal 2013 increased 22 percent to $20,180,000 from $16,601,000 in fiscal 2012;

•

Net income for the year-ended September 30, 2013 of $10,480,000, or $1.31 per share attributable to common stock, compared to net income of $11,113,000, or $1.40 per share attributable to common stock in fiscal 2012. Included in the fiscal 2012 results is a $0.18 per share one-time tax benefit related to a terminated merger agreement;

•

Revenues of $305,299,000 for the year-ended September 30, 2013 compared to $319,274,000 for the year-ended September 30, 2012;

•

Revenues net of third-party reimbursable charges increased 9 percent in fiscal 2013 from fiscal 2012;

•

Fiscal 2013 capital expenditures of $50,069,000 compared to $47,664,000 in fiscal 2012;

•

Purchased 12,000 single-channel Geospace GSX units, 1,000 three-channel GSX units, 2,500 channels of the Wireless Seismic RT System 2 recording system and 10 INOVA vibrator energy source units to increase recording capacity and improve efficiency;

•

Deployed a small crew equipped with 2,500 channels of the Wireless Seismic RT System 2 recording system for small 2-D and 3-D projects as well as microseismic applications;

•

Completed several surface recording microseismic projects;

•

Completed first winter season of operations in Canada;

•

Balanced portfolio of projects primarily in the Eagle Ford Shale, Niobrara Shale, Bakken Shale, Marcellus Shale, Permian Basin including the Cline Shale and Wolfcamp areas, and Mississippi Lime of Kansas and Oklahoma; and

•

Approximately $79 million of working capital at September 30, 2013.

Results of Operations

Fiscal Year Ended September 30, 2013 versus Fiscal Year Ended September 30, 2012

Operating Revenues. Our operating revenues decreased 4% to $305,299,000 in fiscal 2013 from $319,274,000 in fiscal 2012. The revenue decrease in fiscal 2013 was primarily the result of a significant decrease in third-party charges during fiscal 2013 as compared to fiscal 2012 and a decrease in crew utilization during the fourth fiscal quarter. Third-party charges related to our use of helicopter support services, specialized survey technologies and dynamite energy sources in areas of limited access decreased 37% in fiscal 2013 from fiscal 2012. We are reimbursed for these third-party charges by our clients. The decline in third-party charges is primarily a result of our continued operations in the more wide open terrain of the Western United States. Fee revenue net of third-party charges for fiscal 2013 increased 9% from fiscal 2012. The increase in revenues net of third-party charges during fiscal 2013 is a result of an overall increase in production and more favorable contract terms in 2013 as compared to 2012. Increased utilization and the use of cable-less equipment contributed to our increased production in fiscal 2013. Other factors contributing nominally to our increased fee revenue net of third-party changes included our line clearing services initiated during fiscal 2013 and the completion of our first Canadian winter season. Despite decreases in third-party charges and increases in fee revenues net of third-party charges between fiscal 2012 and 2013, we experienced increases in third-party charges, which we believe are temporary, and decreases in fee revenue net of third-party charges in our fourth fiscal quarter.

Operating Costs. Our operating expenses decreased 9% to $234,660,000 in fiscal 2013 from $258,970,000 in fiscal 2012 primarily due to the decrease in reimbursed third-party charges. As discussed above, third-party charges decreased 37% in fiscal 2013 from fiscal 2012. Operating expenses excluding third-party charges in fiscal 2013 increased 9% from fiscal 2012. This increase resulted primarily from increased field personnel and other expenses associated with higher utilization in 2013 as compared to 2012 and expenses associated with our first Canadian winter season. Since the increase in fee revenues net of third-party charges in fiscal 2013 exceeded the growth of operating costs excluding third-party charges, our margins improved during fiscal 2013. 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 increased by $2,159,000 in fiscal 2013 as compared to fiscal 2012 and represented 4.4% of revenues in fiscal 2013 as compared to 3.5% of revenues in fiscal 2012. The primary factor for the increase in general and administrative expenses was additional administrative costs to support our Canadian operations.

We recognized $37,095,000 of depreciation expense in fiscal 2013 as compared to $32,498,000 in fiscal 2012. Depreciation expense increased 14% from fiscal 2012 to 2013 reflecting increased capital expenditures during fiscal 2013. Our depreciation expense is expected to continue to increase in fiscal 2014 as a result of our significant capital expenditures in fiscal 2013.

Our total operating costs for fiscal 2013 were $285,119,000, a decrease of 6% from fiscal 2012 primarily due to the factors described above.

Income Taxes. Income tax expense was $9,090,000 for fiscal 2013 and $5,403,000 for fiscal 2012. The effective tax rates for the income tax provision for fiscal 2013 and 2012 were 46.4% and 32.7%, respectively. In fiscal 2012, transaction costs that had been treated as permanent, non-deductible expenses in fiscal 2011 became fully tax deductible upon the merger’s termination and were treated as a discrete event in 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 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, 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 due 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 our 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 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 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 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.

Use of EBITDA (Non-GAAP measure)

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:

•

the financial performance of our assets without regard to financing methods, capital structures, taxes or historical cost basis;

•

our liquidity and operating performance over time in relation to other companies that own similar assets and that we believe calculate EBITDA in a similar manner; and

•

the ability of our assets to generate cash sufficient for us to pay potential interest costs.

We also understand that such data are used by investors to assess our performance. However, the term EBITDA is not defined under generally accepted accounting principles (“GAAP”), and EBITDA is not a measure of operating income, operating performance or liquidity presented in accordance with GAAP. When assessing our operating performance or liquidity, investors and others should not consider this data in isolation or as a substitute for net income (loss), cash flow from operating activities or other cash flow data calculated in accordance with GAAP. In addition, our EBITDA may not be comparable to EBITDA or similarly titled measures utilized by other companies since such other companies may not calculate EBITDA in the same manner as us. Further, the results presented by EBITDA cannot be achieved without incurring the costs that the measure excludes: interest, taxes, depreciation and amortization.

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

Reconciliation of EBITDA to Net Income (Loss)


	Years Ended September 30,
	2013		2012		2011
	(in thousands)
Net income (loss)	$	10,480	$	11,113	$	(3,246	)
Depreciation		37,095		32,498		30,536
Interest expense (income), net		597		601		132
Income tax expense		9,090		5,403		439

EBITDA	$	57,262	$	49,615	$	27,861

Reconciliation of EBITDA to Net Cash Provided by Operating Activities


	Years Ended September 30,
	2013			2012			2011
	(in thousands)
Net cash provided by operating activities		$70,579			$76,380			$16,951
Changes in working capital and other items		(11,457	)		(24,949	)		12,812
Noncash adjustments to income		(1,860	)		(1,816	)		(1,902	)

EBITDA		$57,262			$49,615			$27,861

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 $70,579,000 for fiscal 2013 and $76,380,000 for fiscal 2012. These amounts primarily reflect an increase in operating margins and steady revenues between periods. Our cash provided by operations was further positively impacted by cash collected from prior periods. Our collection experience during the period expressed as an average number of days in accounts receivable has remained at approximately sixty over the last twelve months. Amounts in our trade accounts receivable that are over sixty days as of September 30, 2013 represents less than 10% of our total trade accounts receivables, which is below our historical levels. We believe our allowance for doubtful accounts of $250,000 at September 30, 2013 is adequate to cover exposures related to our trade account balances.

Net cash used in investing activities was $67,504,000 in fiscal 2013 and $48,580,000 in fiscal 2012. Capital expenditures in fiscal 2013 and 2012 of $48,485,000 and $44,832,000, respectively, net of noncash capital expenditures and noncash capital lease obligations, were funded from excess cash reserves and cash flow from operations. Proceeds of $983,000 from our Third Term Note (as defined below) and $9,346,000 from our Second Term Note (as defined below) supplemented the capital expenditure purchases in 2013 and 2012, respectively. During fiscal 2013 and 2012, excess cash reserves and maturities of certificates of deposit of $10,750,000 and $500,000, respectively, were invested in $30,250,000 and $4,500,000 of certificates of deposit, respectively.

Net cash used by financing activities in fiscal 2013 of $8,043,000 primarily includes $983,000 in proceeds from our Third Term Note that was used to purchase equipment for our Canadian operations and principal payments for all three term notes of $8,898,000. Net cash provided by financing activities in fiscal 2012 was $3,496,000 that primarily represented $9,346,000 in proceeds from our Second Term Note that were used to purchase Geospace Technologies GSR recording equipment and subsequent principal payments for both the Term Note (as defined below) and Second Term Note of $5,814,000.

Capital Expenditures. For fiscal year 2013, we made capital expenditures of $50,069,000, primarily to purchase 12,000 single-channel Geospace Technologies GSX units, 1,000 three-channel Geospace Technologies GSX units, 225 four-channel Geospace Technologies GSR units, for a total increase of 15,900 in Geospace cable-less recording channels. In addition, we purchased 7,000 ARAM ARIES recording channels, 2,500 channels of Wireless Seismic RT System 2, additional conventional geophones, vehicles to improve our fleet and to 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 2014 capital budget of $35,000,000, which will be used, in part, to purchase additional 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.

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, 2013 under the same terms as the previous agreement and permits us to borrow, repay and reborrow, from time to time until June 2, 2015, 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-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 specified ratios as of September 30, 2013 and have the full line of credit available for borrowing. We have not utilized the revolving line of credit during the fiscal years ended September 30, 2013 or 2012.

Our credit loan agreement includes a term loan feature under which we have two outstanding term loans. These term loans were confirmed and brought under the renewed credit loan agreement in June 2013. On June 30, 2011, we entered into a first term loan by obtaining $16,427,000 in financing for the purchase of Geospace Technologies GSR equipment (“Term Note”). The Term Note is repayable over a period of 36 months at $485,444 per month plus any applicable interest in excess of 4%. The 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 4%, and otherwise has the same terms as our revolving line of credit. The Term Note is collateralized by a 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. 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 is 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. See additional discussion in Note 17, “Subsequent Events” to the Consolidated Financial Statements included herein.

On February 12, 2013, our subsidiary Dawson Seismic Services ULC (“DSS”) entered into a promissory note (“Third Term Note”) with Wells Fargo Equipment Finance Company. DSS obtained $983,000 in financing for the purchase of equipment. The Third Term Note is repayable over a period of 36 months at $28,980 per month and bears interest at an implied annual fixed rate of 3.84%. The Third Term Note is collateralized by a security interest in the DSS equipment and matures with all outstanding balances due on February 5, 2016.

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 November 2017. At September 30, 2013, we had leased 83 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, 2013.


	Payments Due by Period (in 000’s)
Contractual Obligations	Total		Within 1 Year		1-2 Years		3-5 Years		After 5 Years
Operating lease obligations (office space)	$	2,742	$	902	$	1,530	$	310	$	—
Capital lease obligations		1,768		837		868		63		—
Debt obligations		11,187		8,421		2,766		—		—

Total	$	15,697	$	10,160	$	5,164	$	373	$	—

In April 2012, we filed a shelf registration statement with the SEC covering the periodic offer and sale of up to $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 generated from operations, cash on hand, through borrowings under our revolving line of credit, additional equipment term 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, 2013, 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.

In some instances, the contract contains certain permitting, surveying and drilling costs that are incorporated into the per unit of data acquired rate. In these circumstances, these set-up costs that occur prior to initiating revenue recognition are capitalized and amortized as data is acquired.

Stock-Based Compensation. We measure all employee stock-based compensation awards, which include stock options, restricted stock and restricted stock units, 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 and Comprehensive Income (Loss) (“Consolidated Statements of Operations”) on a straight-line basis over the vesting period of the related stock options or restricted stock awards.

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. Our effective tax rates differ from the statutory federal rate of 35% for certain items such as 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.

Recently Issued Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” that updated guidance related to disclosure of reclassification amounts out of accumulated other comprehensive income. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. ASU 2013-02 was effective for us as of January 1, 2013. The adoption of this guidance did not have a material impact 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 of credit risk and changes in interest rates. We have not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other derivative financial instruments. During 2012, we began to conduct business in Canada which subjects our results of operations and cash flow to foreign currency exchange rate risk.

Concentration of Credit Risk. Our principal market risks include fluctuations in commodity prices, which affect demand for and pricing of our services, and the risk related to the concentration of our clients in the oil and natural gas industry. Since all of our clients are involved in the oil and natural gas industry, there may be a positive or negative effect on our exposure to credit risk because our clients may be similarly affected by changes in economic and industry conditions. As an example, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our clients. In the normal course of business, we provide credit terms to our clients. Accordingly, we perform ongoing credit evaluations of our clients and maintain allowances for possible losses. We believe that our allowance for doubtful accounts of $250,000 at September 30, 2013 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 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, 2013, our interest rate was 4% for the Term Note and the 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; however, volatility in financial markets may impact our credit risk on cash and short-term investments. At September 30, 2013, cash and cash equivalents totaled $52,405,000.

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A.

CONTROLS AND PROCEDURES

Management’s Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive and principal financial officers, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15(e) and 15d-15(e) under the 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, 2013, 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, 2013 using the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework). Based on this evaluation, we have concluded that, as of September 30, 2013, our internal control over financial reporting was effective. Our internal control over financial reporting as of September 30, 2013 has been audited by Ernst & Young LLP, the independent registered public accounting firm who also audited our financial statements. Their attestation report appears on page F-4.

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, 2013 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B.

OTHER INFORMATION

None.

Part III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 21, 2014, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2013. Certain information with respect to our executive officers is set forth below. We have a code of ethics as defined in Item 406 of Regulation 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. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics for our senior financial officers, including the Chief Executive Officer, if any, either by posting such information on our website at http://www.dawson3d.com in the “Corporate Governance” area of the “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.


Name	Age		Position
Stephen C. Jumper		52	Chairman of the Board of Directors, President and Chief Executive Officer
C. Ray Tobias		56	Executive Vice President, Chief Operating Officer
Christina W. Hagan		58	Executive Vice President, Secretary and Chief Financial Officer
James W. Thomas		59	Executive Vice President, Chief Technical Officer
K.S. Forsdick		62	Senior Vice President

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.

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. In January 2013, Mr. Jumper was elected Chairman of the Board of Directors. 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, First Vice President and as 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.

James W. Thomas. Mr. Thomas joined the Company in 2002 as Chief Geophysicist. Mr. Thomas was elected Vice President of Data Processing in March 2007 and Chief Technical Officer in January 2012. Prior to joining the Company, Mr. Thomas was employed for 21 years by 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.

Item 11.

EXECUTIVE COMPENSATION

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 21, 2014, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2013.

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required with respect to our equity compensation plans is set forth in Item 5 of this Form 10-K. Other information required by Item 12 is incorporated by reference to our definitive proxy statement for our Annual Meeting of Shareholders to be held on January 21, 2014, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2013.

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated by reference to our definitive proxy statement for our Annual Meeting of Shareholders to be held on January 21, 2014, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2013.

Item 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is incorporated by reference to our definitive proxy statement for our Annual Meeting of Shareholders to be held on January 21, 2014, which we expect to file with the Securities and Exchange Commission within 120 days after September 30, 2013.

Part IV

Item 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

(1) Financial Statements.

The following consolidated financial statements of the Company appear on pages F-1 through F-22 and are incorporated by reference into Part II, Item 8:

Reports of Independent Registered Public Accounting Firms

Consolidated Balance Sheets

Consolidated Statements of Operations and Comprehensive Income (Loss)

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to the Consolidated Financial Statements

(2) Financial Statement Schedules.

All schedules are omitted because they are either not applicable or the required information is shown in the financial statements or notes thereto.

(3) Exhibits.

The information required by this item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report of Form 10-K and is hereby incorporated by reference.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, and the State of Texas, on the 11^th day of December, 2013.


DAWSON GEOPHYSICAL COMPANY

By:		/s/ Stephen C. Jumper
		Stephen C. Jumper
		Chairman of the Board of Directors
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Stephen C. Jumper Stephen C. Jumper	President, Chief Executive Officer and Chairman of the Board of Directors (principal executive officer)	12-11-13

/s/ Craig W. Cooper Craig W. Cooper	Director	12-11-13

/s/ Gary M. Hoover Gary M. Hoover	Director	12-11-13

/s/ Ted R. North Ted R. North	Director	12-11-13

/s/ Tim C. Thompson Tim C. Thompson	Director	12-11-13

/s/ Christina W. Hagan Christina W. Hagan	Executive Vice President, Secretary and Chief Financial Officer (principal financial and accounting officer)	12-11-13

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Consolidated Financial Statements of Dawson Geophysical Company	Page
Reports of Independent Registered Public Accounting Firms, dated December 11, 2013		F-2
Consolidated Balance Sheets as of September 30, 2013 and 2012		F-5
Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended September 30, 2013, 2012 and 2011		F-6
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2013, 2012 and 2011		F-7
Consolidated Statements of Cash Flows for the years ended September 30, 2013, 2012 and 2011		F-8
Notes to Consolidated Financial Statements		F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Dawson Geophysical Company

We have audited the accompanying consolidated balance sheet of Dawson Geophysical Company as of September 30, 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for the year ended September 30, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dawson Geophysical Company at September 30, 2013, and the consolidated results of its operations and its cash flows for the year ended September 30, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dawson Geophysical Company’s internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated December 11, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

December 11, 2013

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Dawson Geophysical Company

We have audited the accompanying consolidated balance sheet of Dawson Geophysical Company as of September 30, 2012, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the two-year period ended September 30, 2012. The consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Dawson Geophysical Company as of September 30, 2012 and the results of its operations and its cash flows for each of the years in the two-year period ended September 30, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Dallas, Texas

December 5, 2012

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Dawson Geophysical Company

We have audited Dawson Geophysical Company’s internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Dawson Geophysical Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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.

In our opinion, Dawson Geophysical Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Dawson Geophysical Company as of September 30, 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for the year ended September 30, 2013 and our report dated December 11, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

December 11, 2013

F-4

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED BALANCE SHEETS


	September 30, 2013			September 30, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	52,405,000		$	57,373,000
Short-term investments		23,500,000			4,000,000
Accounts receivable, net of allowance for doubtful accounts of $250,000 at September 30, 2013 and 2012		37,488,000			53,719,000
Prepaid expenses and other assets		737,000			762,000
Current deferred tax asset		1,664,000			1,925,000

Total current assets		115,794,000			117,779,000

Property, plant and equipment		325,464,000			326,030,000
Less accumulated depreciation		(152,231,000	)		(164,634,000	)

Net property, plant and equipment		173,233,000			161,396,000

Total assets	$	289,027,000		$	279,175,000


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	15,880,000		$	18,544,000
Accrued liabilities:
Payroll costs and other taxes		1,850,000			1,802,000
Other		6,154,000			6,425,000
Deferred revenue		3,438,000			3,467,000
Current maturities of notes payable and obligations under capital leases		9,258,000			9,131,000

Total current liabilities		36,580,000			39,369,000

Long-term liabilities:
Notes payable and obligations under capital leases less current maturities		3,697,000			11,179,000
Deferred tax liability		35,690,000			27,678,000

Total long-term liabilities		39,387,000			38,857,000

Commitments and contingencies

Stockholders’ equity:
Preferred stock-par value $1.00 per share; 5,000,000 shares authorized, none outstanding		—			—
Common stock-par value $.33 1/3 per share; 50,000,000 shares authorized, 8,056,943 and 8,031,369 shares issued and outstanding at September 30, 2013 and September 30, 2012, respectively		2,686,000			2,677,000
Additional paid-in capital		94,846,000			93,224,000
Retained earnings		115,528,000			105,048,000

Total stockholders’ equity		213,060,000			200,949,000

Total liabilities and stockholders' equity	$	289,027,000		$	279,175,000

See accompanying notes to the consolidated financial statements.

F-5

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)


	Years Ended September 30,
	2013			2012			2011
Operating revenues	$	305,299,000		$	319,274,000		$	333,279,000
Operating costs:
Operating expenses		234,660,000			258,970,000			292,519,000
General and administrative		13,364,000			11,205,000			13,550,000
Depreciation		37,095,000			32,498,000			30,536,000

		285,119,000			302,673,000			336,605,000
Income (loss) from operations		20,180,000			16,601,000			(3,326,000	)
Other income (expense):
Interest income		63,000			28,000			35,000
Interest expense		(660,000	)		(629,000	)		(167,000	)
Other (expense) income		(13,000	)		516,000			651,000

Income (loss) before income tax		19,570,000			16,516,000			(2,807,000	)
Income tax (expense) benefit:
Current		(817,000	)		(490,000	)		2,929,000
Deferred		(8,273,000	)		(4,913,000	)		(3,368,000	)

		(9,090,000	)		(5,403,000	)		(439,000	)

Net income (loss)	$	10,480,000		$	11,113,000		$	(3,246,000	)

Other comprehensive loss, net of tax:
Realization of losses on investment, net of tax of $2,000	$	—		$	—		$	(4,000	)

Comprehensive income (loss)	$	10,480,000		$	11,113,000		$	(3,250,000	)

Basic income (loss) per share attributable to common stock	$	1.31		$	1.40		$	(0.42	)

Diluted income (loss) per share attributable to common stock	$	1.31		$	1.39		$	(0.42	)

Weighted average equivalent common shares outstanding		7,879,614			7,841,722			7,809,561

Weighted average equivalent common shares outstanding — assuming dilution		7,920,365			7,877,107			7,809,561

See accompanying notes to the consolidated financial statements.

F-6

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


							Additional Paid-in Capital			Accumulated Other Comprehensive Loss
	Common Stock
	Number of Shares			Amount									Retained Earnings			Total
Balance September 30, 2010		7,902,106		$	2,634,000		$	90,406,000		$	4,000		$	97,181,000		$	190,225,000
Net loss														(3,246,000	)		(3,246,000	)
Realization of losses on investment, net of tax											(4,000	)					(4,000	)
Tax deficit resulting from share-based compensation								(453,000	)								(453,000	)
Stock-based compensation expense								1,485,000									1,485,000
Issuance of common stock as compensation		6,479			2,000			184,000									186,000
Forfeiture of restricted stock awards		(4,000	)		(1,000	)											(1,000	)
Shares exchanged for taxes on stock-based compensation		(9,400	)		(3,000	)		(323,000	)								(326,000	)
Exercise of stock options		15,700			5,000			292,000									297,000

Balance September 30, 2011		7,910,885			2,637,000			91,591,000			—			93,935,000			188,163,000
Net income														11,113,000			11,113,000
Stock-based compensation expense								1,245,000									1,245,000
Issuance of common stock as compensation		7,234			3,000			241,000									244,000
Exercise of stock options		9,750			3,000			181,000									184,000
Issuance of restricted stock awards and unearned compensation		103,500			34,000			(34,000	)								—

Balance September 30, 2012		8,031,369			2,677,000			93,224,000			—			105,048,000			200,949,000
Net income														10,480,000			10,480,000
Stock-based compensation expense								1,394,000									1,394,000
Issuance of common stock as compensation		14,484			5,000			398,000									403,000
Forfeiture of restricted stock awards		(900	)		—			—									—
Shares exchanged for taxes on stock-based compensation		(20,160	)		(7,000	)		(767,000	)								(774,000	)
Exercise of stock options		32,150			11,000			597,000									608,000

Balance September 30, 2013		8,056,943		$	2,686,000		$	94,846,000		$	—		$	115,528,000		$	213,060,000

See accompanying notes to the consolidated financial statements.

F-7

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended September 30,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	10,480,000		$	11,113,000		$	(3,246,000	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		37,095,000			32,498,000			30,536,000
Noncash compensation		1,797,000			1,489,000			1,671,000
Deferred income tax expense		8,273,000			4,913,000			3,368,000
Provision for bad debts		63,000			327,000			231,000
Other		(118,000	)		192,000			(516,000	)
Change in current assets and liabilities:
Decrease (increase) in accounts receivable		16,168,000			32,670,000			(30,613,000	)
Decrease in prepaid expenses and other assets		25,000			3,359,000			3,402,000
(Decrease) increase in accounts payable		(2,952,000	)		(1,593,000	)		3,628,000
Decrease in accrued liabilities		(223,000	)		(2,439,000	)		(922,000	)
(Decrease) increase in deferred revenue		(29,000	)		(6,149,000	)		9,412,000

Net cash provided by operating activities		70,579,000			76,380,000			16,951,000

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures, net of noncash capital expenditures summarized below in noncash investing and financing activities		(48,485,000	)		(44,832,000	)		(58,550,000	)
Proceeds from maturity of short-term investments		10,750,000			500,000			22,500,000
Acquisition of short-term investments		(30,250,000	)		(4,500,000	)		(2,500,000	)
Proceeds from disposal of assets		481,000			252,000			741,000
Partial proceeds on fire insurance claim		—			—			1,392,000

Net cash used by investing activities		(67,504,000	)		(48,580,000	)		(36,417,000	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable		983,000			9,346,000			16,427,000
Principal payments on notes payable		(8,898,000	)		(5,814,000	)		(856,000	)
Principal payments on capital lease obligations		(736,000	)		(220,000	)		—
Proceeds from exercise of stock options		608,000			184,000			297,000

Net cash (used) provided by financing activities		(8,043,000	)		3,496,000			15,868,000

Net (decrease) increase in cash and cash equivalents		(4,968,000	)		31,296,000			(3,598,000	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		57,373,000			26,077,000			29,675,000

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	52,405,000		$	57,373,000		$	26,077,000

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest	$	688,000		$	618,000		$	115,000
Cash paid for income taxes	$	1,665,000		$	262,000		$	509,000
Cash received for income taxes	$	42,000		$	3,258,000		$	7,366,000
NONCASH INVESTING AND FINANCING ACTIVITIES:
Increase in accrued purchases of property and equipment	$	288,000		$	1,405,000		$	830,000
Capital lease obligations incurred	$	1,296,000		$	1,427,000		$	—

See accompanying notes to the consolidated financial statements.

F-8

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

Founded in 1952, the Company acquires and processes 2-D, 3-D and multi-component seismic data for its clients, ranging from major oil and gas companies to independent oil and gas operators as well as providers of multi-client data libraries.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Dawson Seismic Services Holdings, Inc. and Dawson Seismic Services ULC. All significant intercompany balances and transactions have been eliminated in consolidation.

Cash Equivalents

For purposes of the financial statements, the Company considers demand deposits, certificates of deposit, overnight investments, money market funds and all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.

Allowance for Doubtful Accounts

Management prepares its allowance for doubtful accounts receivable based on its review of past-due accounts, its past experience of historical write-offs and its 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 the Company’s clients.

Property, Plant and Equipment

Property, plant and equipment is capitalized at historical cost and depreciated over the useful life of the asset. Management’s 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.

Impairment of Long-Lived Assets

Long-lived assets are reviewed 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. Management’s forecast of future cash flows used to perform impairment analysis includes estimates of future revenues and expenses based on the Company’s anticipated future results while considering anticipated future oil and natural gas prices which is fundamental in assessing demand for the Company’s services. If the carrying amounts of the assets exceed the estimated expected undiscounted future cash flows, the Company measures the amount of possible impairment by comparing the carrying amount of the assets to the fair value. No impairment charges were recognized for the years ended September 30, 2013, 2012 or 2011.

Leases

The Company leases certain equipment and vehicles under lease agreements. The Company evaluates each lease to determine its appropriate classification as an operating or capital lease for financial reporting purposes. Any lease that does not meet the criteria for a capital lease is accounted for as an operating lease. The assets and liabilities under capital leases are recorded at the lower of the present value of the minimum lease payments or

F-9

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the fair market value of the related assets. Assets under capital leases are amortized using the straight-line method over the initial lease term. Amortization of assets under capital leases is included in depreciation expense.

Revenue Recognition

Services are provided under cancelable service contracts. These contracts are either “turnkey” or “term” agreements. Under both types of agreements, the Company recognizes revenues when revenue is realizable and services have been 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, revenue is recognized and the client is billed for services performed up to the date of cancellation.

The Company receives reimbursements for certain out-of-pocket expenses under the terms of the service contracts. Amounts billed to clients are recorded in revenue at the gross amount including out-of-pocket expenses that are reimbursed by the client.

In some instances, clients are billed in advance of services performed. In those cases, the Company recognizes the liability as deferred revenue. As services are performed, those deferred revenue amounts are recognized as revenue.

Stock-Based Compensation

The Company measures all employee stock-based compensation awards, which include stock options, restricted stock and restricted stock units, using the fair value method and recognizes compensation cost, net of estimated forfeitures, in its financial statements. The Company records 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 related stock options or restricted stock awards.

Income Taxes

The Company accounts for income taxes by recognizing 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 assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Management determines 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 asset will not be realized. Management’s methodology for recording income taxes requires judgment regarding assumptions and the use of estimates, including determining the annual effective tax rate and the valuation of deferred tax assets, which can create variances between actual results and estimates and could have a material impact on the Company’s provision or benefit for income taxes. The Company’s effective tax rates differ from the statutory federal rate of 35% for certain items such as 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.

F-10

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Use of Estimates in the Preparation of Financial Statements

Preparation of the accompanying financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Because of the use of assumptions and estimates inherent in the reporting process, actual results could differ from those estimates.

2. Short-Term Investments

The Company had short-term investments at September 30, 2013 and 2012 consisting of certificates of deposit with original maturities greater than three months, but less than a year. Certificates of deposit are limited to one per banking institution and no single investment exceeded the FDIC insurance limit at September 30, 2013 or 2012.

3. Fair Value of Financial Instruments

At September 30, 2013 and 2012, the Company’s financial instruments included cash and cash equivalents, short-term investments in certificates of deposit, trade and other receivables, other current assets, accounts payable, other current liabilities, the Term Note and the Second Term Note. At September 30, 2013, the Company’s financial instruments also included the Third Term Note. Due to the short-term maturities of cash and cash equivalents, trade and other receivables, other current assets, accounts payables and other current liabilities, the carrying amounts approximate fair value at the respective balance sheet dates. The carrying value of the Company’s Term Note and Second Term Note approximate their fair value due to the fact that the interest rates on the Term Note and Second Term Note are reset each month based on the prevailing market interest rate. The Company’s Third Term Note approximates its fair value based on a comparison with the prevailing market interest rate. Due to the short-term maturities of the Company’s investments in certificates of deposit, the carrying amounts approximate fair value at the respective balance sheet dates. The fair values of the Company’s notes payable and investments in certificates of deposit are Level 2 measurements in the fair value hierarchy.

4. Property, Plant and Equipment

Property, plant and equipment, together with the related estimated useful lives, were as follows:


	September 30,
	2013			2012			Useful Lives
Land, building and other	$	10,822,000		$	8,641,000			3 to 40 years
Recording equipment		197,134,000			206,642,000			5 to 10 years
Line clearing equipment		937,000			913,000			5 years
Vibrator energy sources		80,309,000			76,813,000			5 to 15 years
Vehicles		35,623,000			32,429,000			1.5 to 10 years
Other(a)		639,000			592,000			—

		325,464,000			326,030,000
Less accumulated depreciation		(152,231,000	)		(164,634,000	)

Net property, plant and equipment	$	173,233,000		$	161,396,000

(a)

Other represents accumulated costs associated with equipment fabrication and modification not yet completed.

F-11

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5. Supplemental Consolidated Balance Sheet Information

Accounts receivable consist of the following at September 30, 2013 and 2012:


	September 30,
	2013			2012
Trade and accrued trade receivables	$	36,751,000		$	53,268,000
Allowance for doubtful accounts		(250,000	)		(250,000	)
Accrued receivable for workers’ compensation stop loss policy		495,000			623,000
Other		492,000			78,000

Total accounts receivable	$	37,488,000		$	53,719,000

Other current liabilities consist of the following at September 30, 2013 and 2012:


	September 30,
	2013		2012
Accrued self-insurance reserves	$	1,865,000	$	2,181,000
Accrued profit sharing		1,313,000		963,000
Income and franchise taxes payable		243,000		1,096,000
Accrued insurance premiums		805,000		—
Other accrued expenses and current liabilities		1,928,000		2,185,000

Total other current liabilities	$	6,154,000	$	6,425,000

6. Debt

The Company’s revolving line of credit loan agreement is with Western National Bank. The agreement was renewed June 2, 2013 under the same terms as the previous agreement. The agreement permits the Company to borrow, repay and reborrow, from time to time until June 2, 2015, up to $20.0 million based on the borrowing base calculation as defined in the agreement. The Company’s obligations under this agreement are secured by a security interest in its accounts receivable, equipment and related collateral. Interest on the facility accrues 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 the Company directs 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. The Company is 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. The Company was in compliance with all covenants including specified ratios as of September 30, 2013 and has the full line of credit available for borrowing. The Company has not utilized the revolving line of credit during the fiscal years ended September 30, 2013 or 2012.

The Company’s credit loan agreement includes a term loan feature under which the Company has two outstanding term loans. These term loans were confirmed and brought under the renewed credit loan agreement in June 2013. On June 30, 2011, the Company entered into the First Term Note by obtaining $16,427,000 in financing for the purchase of Geospace Technologies GSR equipment. The Term Note is repayable over a period of 36 months at $485,444 per month plus any applicable interest in excess of 4%. Interest on the Term Note accrues 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 the Company directs monthly, subject to an interest rate floor of 4%, and otherwise has the same terms as the revolving line of credit. The Term Note is collateralized by a security interest in the Company’s accounts receivable, equipment and related collateral and matures with all outstanding balances due on June 30, 2014.

F-12

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On May 11, 2012, the Company entered into the Second Term Note under its credit loan agreement. The Second Term Note allows the Company to borrow from time to time up to $15.0 million to purchase equipment. The outstanding principal under the Second Term Note is amortized over a period of 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 the Company directs monthly, subject to an interest rate floor of 3.75%, and otherwise has the same terms as the revolving line of credit. The Second Term Note is collateralized by a security interest in the Company’s accounts receivable, equipment and related collateral and matures with all outstanding balances due on May 2, 2015. On July 5, 2012, the Company borrowed $9,346,000 under the Second Term Note to purchase Geospace Technologies GSR recording equipment. See additional discussion in Note 17, “Subsequent Events” to the Consolidated Financial Statements included herein.

On February 12, 2013, the Company’s subsidiary DSS entered into the Third Term Note with Wells Fargo Equipment Finance Company. DSS obtained $983,000 in financing for the purchase of equipment. The Third Term Note is repayable over a period of 36 months at $28,980 per month and bears interest at an implied annual fixed rate of 3.84%. The Third Term Note is collateralized by a security interest in the DSS equipment and matures with all outstanding balances due on February 5, 2016.

In the second quarter of fiscal 2012, the Company 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 November 2017. At September 30, 2013, the Company had leased 83 vehicles under these capital leases.

The Company’s notes payable and obligations under capital leases consist of the following:


	September 30, 2013			September 30, 2012
Term Note	$	4,770,000		$	10,281,000
Second Term Note		5,616,000			8,821,000
Third Term Note		801,000			—
Revolving line of credit		—			—
Obligations under capital leases		1,768,000			1,208,000

	$	12,955,000		$	20,310,000
Less current maturities of notes payable and obligations under capital leases		(9,258,000	)		(9,131,000	)

	$	3,697,000		$	11,179,000

The aggregate maturities of the notes payable and obligations under capital leases at September 30, 2013 are as follows:


October 2013 – September 2014	$	9,258,000
October 2014 – September 2015		3,302,000
October 2015 – September 2016		332,000
October 2016 – September 2017		57,000
October 2017 – September 2018		6,000

	$	12,955,000

7. Stock-Based Compensation

At September 30, 2013, the Company had one stock-based compensation plan. The awards outstanding under this plan and the associated accounting treatment are discussed below.

F-13

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In fiscal year 2007, the Company adopted the Dawson Geophysical Company 2006 Stock and Performance Incentive Plan (the “Plan”). The Plan provides for the issuance of up to 750,000 shares of authorized Company common stock which may be awarded to officers, directors, employees and consultants of the Company in various forms including options, common stock grants, restricted stock grants, restricted stock units and others. Stock option grant prices awarded under the Plan may not be less than the fair market value of the common stock subject to such option on the grant date, and the term of stock options shall extend no more than ten years after the grant date.

Incentive Stock Options:

The Company estimates the fair value of each stock option on the date of grant using the Black-Scholes option pricing model. The expected volatility is based on historical volatility of the Company’s stock. The expected term represents the average period that the Company expects stock options to be outstanding and is determined based on the Company’s historical experience. The risk free interest rate used by the Company as the discounting interest rate is based on the U.S. Treasury rates on the grant date for securities with maturity dates of approximately the expected term. As the Company has not historically declared dividends and does not expect to declare dividends in the near term, the dividend yield used in the calculation is zero. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an option holder will be at or near the value estimated by the Black-Scholes model.

A summary of the Company’s employee stock options as of September 30, 2013, as well as activity during the year then ended is presented below.


	Number of Optioned Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term in Years		Aggregate Intrinsic Value ($000)
Balance as of September 30, 2012		125,550		$	18.91
Exercised		(32,150	)		18.91

Balance as of September 30, 2013		93,400		$	18.91		5.17	$	1,267

Exercisable as of September 30, 2013		93,400		$	18.91		5.17	$	1,267

No options were granted during fiscal years 2013, 2012 or 2011. The total intrinsic value of options exercised during fiscal years 2013, 2012 and 2011 was $518,000, $173,000, and $318,000, respectively. The total fair value of options vested during fiscal years 2013, 2012 and 2011 was $362,000, $362,000, and $362,000, respectively.

A summary of the status of the Company’s nonvested stock option awards as of September 30, 2013 and changes during the year then ended is presented below.


	Number of Nonvested Share Awards			Weighted Average Grant Date Fair Value
Nonvested option awards outstanding September 30, 2012		37,750		$	9.59
Vested		(37,750	)		9.59

Nonvested option awards outstanding September 30, 2013		__		$	__

Outstanding options at September 30, 2013 expire in December 2018 and have an exercise price of $18.91. There was no unrecognized compensation costs related to stock option awards as of September 30, 2013.

Stock options issued under the Plan are incentive stock options. No tax deduction is recorded when options are awarded. If an exercise and sale of vested options results in a disqualifying disposition, a tax deduction for the Company occurs. For the years ended September 30, 2013, 2012 and 2011, there were no excess tax benefits from disqualifying dispositions.

F-14

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash received from option exercises under all share-based payment arrangements during the years ended September 30, 2013, 2012 and 2011 was $608,000, $184,000 and $297,000, respectively.

The Company recognized compensation expense associated with stock option awards of $62,000, $362,000 and $362,000 in fiscal years 2013, 2012 and 2011, respectively, which are included in operating or general and administrative expense as appropriate in the Consolidated Statements of Operations.

Restricted Stock Awards:

There were no restricted stock grants in 2013 or 2011. The Company granted 103,500 shares of restricted stock to employees in fiscal year 2012. The weighted average grant date fair value of restricted stock awards in fiscal year 2012 was $23.55. The fair value of the restricted stock granted equals the market price on the grant date and vests after three years.

A summary of the status of the Company’s nonvested restricted stock awards as of September 30, 2013 and changes during the year then ended is presented below.


	Number of Restricted Share Awards			Weighted Average Grant Date Fair Value
Nonvested restricted shares outstanding September 30, 2012		184,600		$	23.45
Vested		(80,200	)	$	23.33
Forfeited		(900	)	$	23.33

Nonvested restricted shares outstanding September 30, 2013		103,500		$	23.55

The Company recognized compensation expense related to restricted stock awards of $1,307,000, $883,000 and $1,123,000 in fiscal years 2013, 2012 and 2011, respectively, which are included in operating or general and administrative expense as appropriate in the Consolidated Statements of Operations. As of September 30, 2013, there was approximately $1,337,000 of unrecognized compensation cost related to nonvested restricted stock awards granted. This cost is expected to be recognized over a weighted average period of 1.69 years.

Restricted Stock Units:

Beginning in 2013, the Company began granting restricted stock units. The Company granted 2,000 restricted stock units to employees during fiscal year 2013. The weighted average grant date fair value of restricted stock units in fiscal year 2013 was $27.14. The fair value of restricted stock units equals the market price on the grant date. The Company recognized compensation expense related to restricted stock units of approximately $25,000 during 2013, which is included in operating or general and administrative expense as appropriate in the Consolidated Statements of Operations. As of September 30, 2013, there was approximately $29,000 of unrecognized compensation cost related to nonvested restricted stock units. This cost is expected to be recognized over a weighted average period of 0.81 years.

Common Stock Awards:

The Company granted common shares with immediate vesting to outside directors and employees in fiscal years 2013, 2012 and 2011:


	Number of Shares Granted		Weighted Average Grant Date Fair Value
2013		14,484	$	27.83
2012		7,234	$	33.64
2011		6,479	$	28.69

The Company recognized expense of $403,000, $244,000 and $186,000 in fiscal years 2013, 2012 and 2011, respectively, as well as the related tax benefit associated with these awards in operating or general and administrative expense as appropriate in the Consolidated Statements of Operations.

F-15

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. Employee Benefit Plans

The Company provides a 401(k) plan as part of its employee benefits package in order to retain quality personnel. During fiscal years 2013, 2012 and 2011, the Company elected to match 100% of the employee contributions up to a maximum of 6% of the participant’s gross salary. The Company’s matching contributions for fiscal 2013, 2012 and 2011 were approximately $1,747,000, $1,521,000 and $1,366,000, respectively.

9. Advertising Costs

Advertising costs are charged to expense as incurred. Advertising costs totaled $319,000, $340,000 and $370,000 during the fiscal years ended September 30, 2013, 2012 and 2011, respectively.

10. Income Taxes

The Company recorded income tax expense in the current year of $9,090,000, as compared to $5,403,000 and $439,000 in 2012 and 2011, respectively.

Income tax expense from operations is comprised of the following:


	Year Ended September 30,
	2013		2012			2011
Current federal expense (benefit)	$	124,000	$	(10,000	)	$	(3,167,000	)
Current state expense		693,000		500,000			238,000
Deferred federal expense		6,251,000		4,737,000			3,920,000
Deferred state expense (benefit)		2,022,000		176,000			(552,000	)

Total	$	9,090,000	$	5,403,000		$	439,000

The income tax provision differs from the amount computed by applying the statutory federal income tax rate to income (losses) from continuing operations before income taxes as follows:


	Year Ended September 30,
	2013			2012			2011
Tax expense (benefit) computed at statutory rate of 35%	$	6,850,000		$	5,781,000		$	(982,000	)
Change in valuation allowance		1,265,000			—			(19,000	)
State income tax expense (benefit), net of federal tax		1,486,000			433,000			(284,000	)
Foreign losses		(987,000	)		—			—
Transaction costs		—			(1,353,000	)		1,353,000
Other		476,000			542,000			371,000

Income tax expense	$	9,090,000		$	5,403,000		$	439,000

F-16

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The principal components of the Company’s net deferred tax liability are as follows:


	September 30,
	2013			2012
Deferred tax assets:
Deferred revenue	$	1,255,000		$	1,265,000
Restricted stock		390,000			579,000
Workers’ compensation		224,000			270,000
State tax net operating loss (NOL) carry forward		802,000			691,000
Federal tax NOL carry forward		9,012,000			12,776,000
Foreign tax NOL carry forward		952,000			—
Self-insurance		286,000			298,000
Canadian start-up costs		405,000			153,000
AMT credit carry forward		310,000			177,000
Other		166,000			210,000

Total gross deferred tax assets		13,802,000			16,419,000
Less valuation allowance		(1,265,000	)		—

Total net deferred tax assets		12,537,000			16,419,000
Deferred tax liabilities:
Property and equipment		(46,563,000	)		(42,172,000	)

Total deferred tax liabilities		(46,563,000	)		(42,172,000	)

Net deferred tax liability	$	(34,026,000	)	$	(25,753,000	)

Current portion of net deferred tax asset/liability	$	1,664,000		$	1,925,000
Non-current portion of net deferred tax asset/liability		(35,690,000	)		(27,678,000	)

Total net deferred tax liability	$	(34,026,000	)	$	(25,753,000	)

At September 30, 2013, the Company had a gross NOL for U.S. federal income tax purposes of approximately $25,750,000. This NOL expires in 2031. The Company will carry forward the net federal NOL of approximately $9,012,000. The Company also had net state NOLs that will affect state taxes of approximately $802,000 at September 30, 2013. State NOLs will begin to expire in 2015. Carryback provisions are not allowed by all states, so the entire state NOLs give rise to a deferred tax asset. Several of these carryforwards are primarily available in states where the Company believes the assets cannot be deemed to be more likely than not realizable. Based on management’s belief that the net operating loss carryforwards are not realizable, a $278,000 valuation allowance was established to offset these deferred tax assets as of September 30, 2013. The Company also has Canadian deferred tax assets that will begin to expire in 2032. The Company has recorded a valuation allowance of $987,000 against the Canadian deferred tax asset because management believes it is currently not more likely than not to be realizable. The Company had no valuation allowances as of September 30, 2012.

As of September 30, 2013, the Company did not recognize any liabilities for unrecognized tax benefits. All of the liabilities for unrecognized tax benefits totaling $161,000 lapsed in the statutes of limitations during fiscal 2012. The Company did not record any changes in prior year tax positions, current year tax positions or settlements with taxing authorities related to uncertain tax positions during fiscal 2013 or 2012.

The Company’s practice is to recognize interest and penalties related to unrecognized tax benefits in income tax expense. There were no interest and penalties recognized in fiscal year 2013. In fiscal year 2012 and 2011, there were interest and penalties included in the Consolidated Statements of Operations of $(98,000) and $(11,000), respectively.

F-17

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. Net Income (Loss) per Share Attributable to Common Stock

Net income (loss) per share attributable to common stock is calculated using the two-class method. The two-class method is an allocation method of calculating earnings (loss) per share when a company’s capital structure includes participating securities that have rights to undistributed earnings. The Company’s employees and officers that hold unvested restricted stock would be entitled to dividends if the Company were to pay dividends.

The Company’s basic net income (loss) per share attributable to common stock is computed by reducing the Company’s net income by the net income allocable to unvested restricted stockholders that have a right to participate in undistributed earnings. The Company’s employees and officers that hold unvested restricted stock do not participate in losses because they are not contractually obligated to do so. Accordingly, no losses are allocated to these unvested restricted stockholders. The undistributed earnings are allocated based on the relative percentage of the weighted average shares of unvested restricted stock and the total of the weighted average common shares outstanding plus the weighted average unvested restricted stock shares. The basic net income (loss) per share attributable to common stock is computed by dividing the net income (loss) attributable to common stock by the weighted average shares outstanding. The Company’s dilutive net income (loss) per share attributable to common stock is computed by adjusting basic net income (loss) per share attributable to common stock by diluted income allocable to unvested restricted stock divided by weighted average diluted shares outstanding. A reconciliation of the basic and diluted earnings (loss) per share attributable to common stock is as follows:


	Year Ended September 30,
	2013			2012(a)			2011
				(in 000’s)
Net income (loss)	$	10,480		$	11,113		$	(3,246	)
Income allocable to unvested restricted stock		(136	)		(158	)		—

Basic income (loss) attributable to common stock	$	10,344		$	10,955		$	(3,246	)

Reallocation of participating earnings		1			—			—

Diluted income (loss) attributable to common stock	$	10,345		$	10,955		$	(3,246	)

Weighted average common shares outstanding:
Basic:		7,879,614			7,841,722			7,809,561
Dilutive common stock options and restricted stock units		40,751			35,385			—

Diluted:		7,920,365			7,877,107			7,809,561

Basic income (loss) attributable to a share of common stock	$	1.31		$	1.40		$	(0.42	)

Diluted income (loss) attributable to a share of common stock	$	1.31		$	1.39		$	(0.42	)

(a)

The 2012 earnings per share calculations have been adjusted for the two-class method to reflect restricted shares that were not reflected as participating in the prior period. Basic earnings per share as previously reported for year ended September 30, 2012 was $1.42. Diluted earnings per share as previously reported for the year-ended September 30, 2012 was $1.40. Basic weighted average shares outstanding as previously reported for the year ended September 30, 2012 was 7,841,722. Diluted weighted average shares outstanding as previously reported for the year ended September 30, 2012 was 7,931,593. The impact on all prior period financial statements is deemed immaterial.

The Company had a net loss in 2011. As a result, the numerator for diluted loss per share attributable to common stock is the same as for basic loss per share attributable to common stock and the denominator for diluted loss per share attributable to common stock is the same as the denominator for basic loss per share attributable to common stock for this period.

F-18

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following weighted average numbers of certain securities have been excluded from the calculation of diluted income (loss) per share attributable to common stock, as their effects would be anti-dilutive.


	Year Ended September 30,
	2013		2012		2011
Stock options		—		—		140,487
Restricted stock		—		46,273		105,655

Total		—		46,273		246,142

12. Major Clients

The Company operates in only one business segment, contract seismic data acquisition and processing services. The major clients in fiscal 2013, 2012 and 2011 have varied. Sales to these clients, as a percentage of operating revenues that exceeded 10%, were as follows:


	2013			2012			2011
A		19	%		—			—
B		17	%		—			24	%
C		—			21	%		27	%

13. Commitments and Contingencies

From time to time, the Company is a party to various legal proceedings arising in the ordinary course of business. Although the Company cannot predict the outcomes of any such legal proceedings, management believes that the resolution of pending legal actions will not have a material adverse effect on the Company’s financial condition, results of operations or liquidity as the Company believes it is adequately indemnified and insured.

The Company experiences contractual disputes with its clients from time to time regarding the payment of invoices or other matters. While the Company seeks to minimize these disputes and maintain good relations with its clients, the Company has in the past, and may in the future, experience disputes that could affect its revenues and results of operations in any period.

The Company has non-cancelable operating leases for office space in Midland, Houston, Denver, Oklahoma City, Pittsburgh and Calgary, Alberta.

The following table summarizes payments due in specific periods related to the Company’s contractual obligations with initial terms exceeding one year as of September 30, 2013.


	Payments Due by Period (in 000’s)
	Total		Within 1 Year		1-2 Years		3-5 Years		After 5 Years
Operating lease obligations (office space)	$	2,742	$	902	$	1,530	$	310	$	—

Some of the Company’s operating leases contain predetermined fixed increases of the minimum rental rate during the initial lease term. For these leases, the Company recognizes the related expense on a straight-line basis and records deferred rent as the difference between the amount charged to expense and the rent paid. Rental expense under the Company’s operating leases with initial terms exceeding one year was $900,000, $805,000, and $717,000 for fiscal 2013, 2012 and 2011, respectively.

As of September 30, 2013, the Company had unused letters of credit totaling approximately $580,000. The Company’s letters of credit principally back obligations associated with the Company’s self-insured retention on workers’ compensation claims. Effective in fiscal 2012, the Company was no longer self-insured for workers’

F-19

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

compensation claims after October 1, 2011. The unused letters of credit outstanding at September 30, 2013 are associated with workers’ compensation claims outstanding prior to October 1, 2011.

14. Rights Agreement

On July 8, 2009, the Board of Directors of the Company authorized and declared a dividend to the holders of record at the close of business on July 23, 2009 of one Right (a “Right”) for each outstanding share of the Company’s common stock. When exercisable, each Right will entitle the registered holder to purchase from the Company a unit consisting of one one-hundredth of a share (a “Fractional Share”) of Series A Junior Participating Preferred Stock, par value $1.00 per share, of the Company (the “Preferred Shares”), at a purchase price of $130.00 per Fractional Share, subject to adjustment (the “Purchase Price”). The description and terms of the Rights are set forth in a Rights Agreement (the “Rights Agreement”) effective as of the close of business on July 23, 2009 as it may from time to time be supplemented or amended between the Company and Computershare Shareowner Services LLC (formerly Mellon Investor Services LLC), as Rights Agent. The Rights Agreement replaced the previous rights plan that was originally adopted in 1999 which expired on July 23, 2009.

Initially, the Rights are attached to all certificates representing outstanding shares of Common Stock. The Rights will only separate from the Common Stock and a “Distribution Date” will only occur, with certain exceptions, upon the earlier of (i) ten days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of 15% or more of the outstanding shares of Common Stock, or (ii) ten business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. In certain circumstances, the Distribution Date may be deferred by the Board of Directors.

The Rights are not exercisable until the Distribution Date and will expire at the close of business on July 23, 2019, unless earlier redeemed or exchanged by the Company as described below.

In the event (a “Flip-In Event”) that a person becomes an Acquiring Person (except pursuant to a tender or exchange offer for all outstanding shares of Common Stock at a price and on terms that a majority of the directors of the Company who are not, and are not representatives, nominees, Affiliates or Associates of, an Acquiring Person or the person making the offer determines to be fair to and otherwise in the best interests of the Company and its shareholders (a “Permitted Offer”)), each holder of a Right will thereafter have the right to receive, upon exercise of such Right, a number of shares of Common Stock (or, in certain circumstances, cash, property or other securities of the Company) having a Current Market Price (as defined in the Rights Agreement) equal to two times the exercise price of the Right. Notwithstanding the foregoing, following the occurrence of any Triggering Event, all Rights that are, or (under certain circumstances specified in the Rights Agreement) were, beneficially owned by or transferred to an Acquiring Person (or by certain related parties) will be null and void in the circumstances set forth in the Rights Agreement. However, Rights are not exercisable following the occurrence of any Flip-In Event until such time as the Rights are no longer redeemable by the Company as set forth below.

In the event (a “Flip-Over Event”) that, at any time from and after the time an Acquiring Person becomes such, (i) the Company is acquired in a merger or other business combination transaction (other than certain mergers that follow a Permitted Offer), or (ii) 50% or more of the Company’s assets, cash flow or earning power is sold or transferred, each holder of a Right (except Rights that are voided as set forth above) shall thereafter have the right to receive, upon exercise, a number of shares of common stock of the acquiring company having a Current Market Price equal to two times the exercise price of the Right. Flip-In Events and Flip-Over Events are collectively referred to as “Triggering Events.”

At any time until ten days following the first date of public announcement of the occurrence of a Flip-In Event, the Company may redeem the Rights in whole, but not in part, at a price of $0.01 per Right, payable, at the option of the Company, in cash, shares of Common Stock or such other consideration as the Board of

F-20

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Directors may determine. After a person becomes an Acquiring Person, the right of redemption is subject to certain limitations in the Rights Agreement.

At any time after the occurrence of a Flip-In Event and prior to a person’s becoming the beneficial owner of 50% or more of the shares of Common Stock then outstanding or the occurrence of a Flip-Over Event, the Company may exchange the Rights (other than Rights owned by an Acquiring Person or an affiliate or an associate of an Acquiring Person, which will have become void), in whole or in part, at an exchange ratio of one share of Common Stock, and/or other equity securities deemed to have the same value as one share of Common Stock, per Right, subject to adjustment.

Until a Right is exercised, the holder thereof, as such, will have no rights as a shareholder of the Company, including, without limitation, the right to vote or to receive dividends.

15. Recently Issued Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” that updated guidance related to disclosure of reclassification amounts out of accumulated other comprehensive income. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source and the income statement line items affected by the reclassification. ASU 2013-02 was effective for the Company as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company’s financial statements.

16. Concentrations of Credit Risk

Financial instruments that potentially expose the Company to concentrations of credit risk at any given time may consist of cash and cash equivalents, money market funds and overnight investment accounts, short-term investments in certificates of deposit, trade and other receivables and other current assets. At September 30, 2013 and 2012, the Company had deposits with domestic and international banks in excess of federally insured limits. Management believes the credit risk associated with these deposits is minimal. Money market funds seek to preserve the value of the investment, but it is possible to lose money investing in these funds.

The Company’s sales are to clients whose activities relate to oil and natural gas exploration and production. The Company generally extends unsecured credit to these clients; therefore, collection of receivables may be affected by the economy surrounding the oil and natural gas industry or other economic conditions. The Company closely monitors extensions of credit and may negotiate payment terms that mitigate risk. For the year ended September 30, 2013, sales to the Company’s largest client represented 19% of its revenues as compared to less than 10% of its revenues at September 30, 2012. The sales to the Company’s second largest client represented 17% of its revenues at September 30, 2013 as compared to less than 10% of its revenues at September 30, 2012. The remaining balance of the Company’s fiscal 2013 revenues was derived from varied clients and none represented 10% or more of its fiscal 2013 revenues.

17. Subsequent Events

On December 4, 2013, the Company entered into a new Multiple Advance Term Note dated as of December 2, 2013 (“Fourth Term Note”) under the credit loan agreement with Western National Bank. The Fourth Term Note allows the Company to borrow from time to time up to $10.0 million to purchase equipment. Per the agreement, the Company will be unable to receive an advance for the remainder of the $15.0 million balance of the Second Term Note. The outstanding principal under the Fourth Term Note will be amortized over a period of 36 months. The Fourth Term Note bears interest at an annual fixed rate equal to 3.16%, and otherwise

F-21

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

has the same terms as the revolving line of credit. The Fourth Term Note is collateralized by a security interest in the Company’s accounts receivable, equipment and related collateral and matures with all outstanding balances due on December 2, 2016. On December 5, 2013, the Company borrowed the full amount of $10,000,000 under the Fourth Term Note to purchase Geospace Technologies GSX recording equipment.

18. Quarterly Consolidated Financial Data (Unaudited)


	Quarter Ended
	December 31		March 31		June 30(a)		September 30(a)
Fiscal 2013:
Operating revenues	$	76,629,000	$	83,350,000	$	75,647,000	$	69,673,000
Income (loss) from operations	$	5,194,000	$	10,598,000	$	6,851,000	$	(2,463,000	)
Net income (loss)	$	2,928,000	$	6,279,000	$	4,063,000	$	(2,790,000	)
Basic income (loss) per share attributable to common stock	$	0.36	$	0.78	$	0.50	$	(0.35	)
Diluted income (loss) per share attributable to common stock	$	0.36	$	0.78	$	0.50	$	(0.35	)
Fiscal 2012:
Operating revenues	$	92,382,000	$	85,546,000	$	68,348,000	$	72,998,000
Income from operations	$	3,226,000	$	9,446,000	$	1,798,000	$	2,131,000
Net income	$	3,231,000	$	5,589,000	$	1,141,000	$	1,152,000
Basic income per share attributable to common stock	$	0.41	$	0.71	$	0.14	$	0.14
Diluted income per share attributable to common stock	$	0.41	$	0.70	$	0.14	$	0.14

(a)

The June 30, 2012 and September 30, 2012 earnings per share calculations have been adjusted for the two-class method to reflect restricted shares that were not reflected as participating in the prior period. Basic earnings per share as previously reported for the quarters ended June 30, 2012 and September 30, 2012 were both $0.15. Diluted earnings per share as previously reported for the quarter ended September 30, 2012 was $0.15. The impact on all prior period financial statements is deemed immaterial.

Basic and diluted income (loss) per share attributable to common stock are computed independently for each of the quarters presented. Therefore, the sum of quarterly basic and diluted information may not equal the annual basic and diluted income (loss) per share attributable to common stock.

F-22

INDEX TO EXHIBITS


Number		Exhibit

3.1		Second Restated Articles of Incorporation of the Company, as amended (filed on February 9, 2007 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q (File No. 000-10144) and incorporated herein by reference and filed on November 28, 2007 as Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

3.2		Second Amended and Restated Bylaws of the Company, as amended (filed on November 23, 2010 as Exhibit 3.2 to the Company’s Annual Report on Form 10-K (File No. 001-34404) and incorporated herein by reference).

3.3		Amendment No. 2 to Second Amended and Restated Bylaws, as amended, of the Company (filed on March 21, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

3.4		Amendment No. 3 to Second Amended and Restated Bylaws, as amended, of the Company (filed on November 30, 2012 as Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

3.5		Statement of Resolution Establishing Series of Shares of Series A Junior Participating Preferred Stock of the Company (filed on July 9, 2009 as Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

4.1		Rights Agreement effective as of July 23, 2009 between the Company and Mellon Investor Services LLC as Rights Agent, which includes as Exhibit A the form of Statement of Resolution Establishing Series of Shares of Series A Junior Participating Preferred Stock setting forth the terms of the Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (filed on July 9, 2009 as Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

10.1†		Dawson Geophysical Company 2006 Stock and Performance Incentive Plan (the “2006 Plan”), dated November 28, 2006 (filed on January 29, 2007 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

10.2†		Dawson Geophysical Company 2004 Incentive Stock Plan (filed on March 12, 2004 as Exhibit 10.1 to the Company’s Registration Statement on Form S-8 (File No. 333-113576) and incorporated herein by reference).

10.3†		Form of Restricted Stock Agreement for the 2006 Plan (filed on August 6, 2007 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

10.4†		Form of Restricted Stock Agreement for the 2006 Plan (filed on February 11, 2008 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (File No. 000-10144) and incorporated herein by reference).

10.5*†		Form of Restricted Stock Agreement for the 2006 Plan.

10.6*†		Form of Restricted Stock Unit Agreement for the 2006 Plan.

10.7†		Form of Stock Option Agreement for the 2006 Plan (filed on August 6, 2007 as Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

10.8†		Form of Stock Option Agreement for the 2006 Plan (filed on February 11, 2008 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q (File No. 000-10144) and incorporated herein by reference).

10.9*†		Form of Stock Option Agreement for the 2006 Plan.

10.10†		Description of Profit Sharing Plan (filed on December 3, 2007 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).


Number		Exhibit

10.11†		Description of Profit Sharing Plan (filed on September 29, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 000-10144) and incorporated herein by reference).

10.12†		Summary of Non-Employee Director Compensation (filed on February 9, 2009 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (File No. 000-10144) and incorporated herein by reference).

10.13†		Dawson Geophysical 2014 Annual Incentive Plan (filed on November 25, 2013 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

10.14		Form of Master Geophysical Data Acquisition Agreement (filed on December 5, 2012 as Exhibit 10.10 to the Company’s Annual Report on Form 10-K (File No. 000-34404) and incorporated herein by reference).

10.15		Form of Supplemental Agreement to Master Geophysical Data Acquisition Agreement (filed on December 5, 2012 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K (File No. 000-34404) and incorporated herein by reference).

10.16†		Form of Indemnification Agreement with Directors and Officers of the Company (filed on March 21, 2011 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

10.17		Revolving Line of Credit and Term Loan Agreement, dated as of June 30, 2011, between the Company and Western National Bank (filed on August 9, 2011 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (File No. 001-34404) and incorporated herein by reference).

10.18		Security Agreement, dated as of June 30, 2011, between the Company and Western National Bank (filed on August 9, 2011 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (File No. 001-34404) and incorporated herein by reference).

10.19		Multiple Advance Term Note Agreement, dated as of May 11, 2012, between the Company and Western National Bank (filed on August 9, 2012 as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (File No. 001-34404) and incorporated herein by reference).

10.20		Security Agreement, dated as of May 11, 2012, between the Company and Western National Bank (filed on August 9, 2012 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (File No. 001-34404) and incorporated herein by reference).

10.21		Revolving Line of Credit and Term Loan Agreement, dated as of June 2, 2013, between the Company and Western National Bank (filed on June 26, 2013 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

10.22		Security Agreement, dated as of June 2, 2013, between the Company and Western National Bank (filed on June 26, 2013 as Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

10.23		Multiple Advance Term Note Agreement, dated as of December 2, 2013, between the Company and Western National Bank (filed on December 10, 2013 as Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

10.24		Security Agreement, dated as of December 2, 2013, between the Company and Western National Bank (filed on December 10, 2013 as Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-34404) and incorporated herein by reference).

21.1*		List of Subsidiaries.

23.1*		Consent of Ernst & Young LLP.

23.2*		Consent of KPMG LLP.

31.1*		Certification of Chief Executive Officer of Dawson Geophysical Company pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Chief Financial Officer of Dawson Geophysical Company pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.


Number		Exhibit

32.1*		Certification of Chief Executive Officer of Dawson Geophysical Company pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”

32.2*		Certification of Chief Financial Officer of Dawson Geophysical Company pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. Pursuant to SEC Release 34-47551, this Exhibit is furnished to the SEC and shall not be deemed to be “filed.”

101		The following materials from the Company’s Annual Report on Form 10-K for the year ended September 30, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at September 30, 2013 and September 30, 2012, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended September 30, 2013, 2012 and 2011, (iii) Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2013, 2012 and 2011, (iv) Consolidated Statements of Cash Flows for the years ended September 30, 2013, 2012 and 2011, and (v) Notes to Consolidated Financial Statements.

*	Filed herewith.

†	Identifies exhibit that consists of or includes a management contract or compensatory plan or arrangement.