Dawson Geophysical Company Annual Report 2012

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FY2012 Annual Report · Dawson Geophysical Company

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N A S D A Q L i s t e d : D W S N w w w. d a w s o n 3 d . c o m

C o r p o r a t e O f f i c e s

D i r e c t o r s

O f f i c e r s

508 West Wall, Suite 800
Midland, Texas 79701-5010

Phone: 432-684-3000
432-684-3030
Fax:
info@dawson3d.com
Email:

Annual Meeting
The Annual Meeting of Shareholders will
be held January 22, 2013, at 10:00 a.m.
at The Petroleum Club of Midland,
501 West Wall, Midland, Texas 79701

Registrar and Transfer Agent
Computershare Shareowner Services LLC
Jersey City, New Jersey

Stock Exchange Listing
Nasdaq Global MarketSM
Symbol: DWSN

Independent Public Accountants
KPMG LLP
Dallas, Texas

L. Decker Dawson
Chairman of the Board

Stephen C. Jumper
President and
Chief Executive Officer

C. Ray Tobias
Executive Vice President
and Chief Operating Officer

Christina W. Hagan
Executive Vice President,
Secretary and Chief Financial Officer

James W. Thomas
Executive Vice President
and Chief Technology Officer

K.S. Forsdick
Senior Vice President

Melody Y. Crowl
Treasurer

Paul H. Brown
Sugar Land, Texas
Management Consultant

Craig W. Cooper
Cypress, Texas
Retired Geophysicist

L. Decker Dawson
Midland, Texas
Chairman of the Board
of the Company

Gary M. Hoover, Ph.D.
Bartlesville, Oklahoma
Retired Geophysicist

Stephen C. Jumper
Midland, Texas
President and Chief Executive Officer
of the Company

Jack D. Ladd
Midland, Texas
Dean and Professor of Management
in The School of Business at UTPB

Ted R. North
Edmond, Oklahoma
Certified Public Accountant

Tim C. Thompson
Midland, Texas
Management Consultant

Forms 10-Q and 10-K reports will be available on the
internet at www.sec.gov each quarter, and additional
information will be available at www.dawson3d.com.

C o r p o r a t e P r o f i l e

2 0 1 2 H i g h l i g h t s

Founded in 1952, Dawson Geophysical Company
is a leading provider of onshore seismic data
acquisition and processing services in the
continental United States. The Company acquires
and processes 2-D, 3-D and multi-component
seismic data for its clients. For six decades,
Dawson has remained committed to helping
exploration and development companies, both
large and small, identify subsurface conditions
conducive to the accumulation of oil and natural
gas. As it has become increasingly difficult to
identify and develop hydrocarbon reservoirs,
there is an increased need for higher resolution
subsurface images. Today, Dawson’s experienced
staff and technical services are in greater
demand as a result of continued exploration and
development activities across the United States
and in Canada.

•

Increasing demand for services fueled six
consecutive quarters of profitability and first
full year of profitability since fiscal 2009;

• Strengthened order book capable of sustaining
fourteen data acquisition crews well into
fiscal 2013;

• Purchased 10,500 single-channel Geospace
GSR units, 3,000 GSR three-channel units
with three component geophones and 19
INOVA vibrator energy source units to increase
recording capacity and improve efficiency;

• Balanced portfolio of projects in the Eagle
Ford Shale, Niobrara Shale, Bakken Shale,
Marcellus Shale, Permian Basin and
Mississippi Lime;

• $78 million of working capital at
September 30, 2012; and

• Awarded first contract in Canada for the

deployment of the Company’s first Canadian
data acquisition crew during the 2013
winter season.

$49,615

161,000

167,000

119,000

Channels

2010 2011 2012

169

157

Energy
Sources

147

2010 2011 2012

EBITDA
(in thousands)

$13,136

$27,861

2010 2011 2012

$333,279

$319,274

$205,272

Revenue
(in thousands)

Earnings
Per
Share

2010 2011 2012

$1.42

($1.20)

($0.42)

2010 2011 2012

L e t t e r t o
S h a r e h o l d e r s

The year is 1952. The United States is the
world’s largest oil producer. It is a time when
the 2-D seismic data acquisition method is
the industry standard technology of choice
for oil and natural gas exploration. It was
at this time when Decker Dawson and your
Company first opened its doors for business.

That was 60 years ago. And the values
upon which your Company was built —
the values of hard work, commitment and
dedication — are no less true today than
they were in 1952. It is upon these values
that Dawson Geophysical grew from a small
operator with one 24-channel seismic data

acquisition crew into the largest geophysical
company in the continental United States
with fourteen crews and 167,000 seismic
channels. What’s more, the success of our
operations can be seen in the dedication of
our employees, the commitment we provide
our clients each day and the loyalty of our
shareholders.

In fiscal 2012, much has changed, but
not the values upon which your Company
was founded. Investments in technology,
people and client services continued to
pay strong dividends in fiscal 2012, as
they did in 1952. Improved efficiencies

After opening a small office in Calgary, Alberta
with a limited, but highly experienced staff,
Dawson Seismic Services executed its first
contract to deploy a data acquisition crew in
the winter months of 2013.

Today, we are experiencing seismic demand
near record levels. Our order book is sufficient
to sustain fourteen data acquisition crews well
into fiscal year 2013. A majority of our work is
now focused on oil and liquids-rich plays much
like a year ago. These plays, typically located in
the western portion of the United States, are often
situated on open ranges and larger ranches.
This shift, a shift away from the densely wooded
environments of the northeast, has resulted in a
significant reduction in third-party charges.

Growth Opportunities

Oil and liquids-rich plays fuel
growth opportunities

Order book at multi-year highs and
capable of sustaining fourteen
crews well into fiscal year 2013

Access to the Canadian seismic market

Today, third-party charges constitute
approximately 25% - 35% of your
Company’s overall revenue, near historical
levels, compared to approximately
45% - 50% over the past few years.

allow us to complete projects and produce
higher resolution images, at times ahead of
schedule. These increased efficiencies further
enable us to convert a greater percentage of
our project order book into fee revenue. Fee
revenue increased by 13 percent from fiscal
2011 to fiscal 2012, earnings increased to
$1.42 per share from a loss of $0.42 per
share and EBITDA increased to $49,615,000
from $27,861,000.

In addition, our project order book
continues to grow, largely as a result of our
investment in people, equipment and client
services. Today, we own and operate the
most extensive seismic equipment base
in the continental United States. We have
more than 167,000 seismic channels
to serve our clients by producing higher
resolution subsurface images and increasing
efficiencies. We maintain the most up-to-date
technology and resources in the industry,
including 161 energy source units and eight
envirovibe units. We operate fourteen data
acquisition crews who serve our valued
clients in every major basin across the
continental United States.

New Equipment Purchases
and Upgrades Lead to

Improved contract terms

Increased operational efficiencies

Faster project completion cycles
and project throughput for clients

In addition, your Company’s growth
opportunities are no longer limited to the
United States. In fiscal 2012, we made the
decision to enter the Canadian seismic market.

As we write this letter to you, our valued
shareholders, we pass through yet another
phase in the evolution of your Company.
In November, your founder and chairman,
Decker Dawson, informed the Board he
will not sit for re-election to the Board of
Directors. In response, the Board elected
him Chairman Emeritus in honor of his
contribution to the creation and growth of
what has become a premier name brand
company within the geophysical industry.
It is upon his personal values that this
Company was founded, built and is
maintained today. But the story does not
end. Mr. Dawson will continue to consult,
advise and attend the Board of Directors
meetings as a valued employee of your
Company as we step into the next
60 years. His values and legacy live
strong as our guide into tomorrow.

Celebrated past, focused future.

We wish all of you a happy, joyous and
safe holiday season.

L. Decker Dawson
Chairman

Stephen C. Jumper
President,
Chief Executive

Officer

December 5, 2012

As we continue to celebrate and learn
from the past, we are also focused on the
future. During fiscal 2012, we invested
$47,664,000 in an additional 10,500
Geospace GSR single-channel units,
3,000 Geospace GSR three-channel units,
nineteen INOVA vibrator energy source
units, additional geophones, cables and
vehicles, along with maintenance capital
requirements.

Our Board of Directors has approved an
initial capital budget of $40,000,000 for
fiscal 2013. The majority of the budget
will be invested in additional energy
sources and cable-less recording channels.
The expenditures are necessary to meet the
continued demand for higher channel count
surveys in virtually every producing basin in
which we operate. The increase in channel
count and energy sources provides the
ability to produce higher resolution images
with added efficiencies. Moreover, our ability
to service our valued clients faster and
more efficiently is leading to improved
contract terms and growth opportunities.
It is this increasing demand for services
that further fueled our sixth consecutive
quarter of profitability and our first full year
of profitability since fiscal 2009.

Calendar year 2012 is also important for
another reason. For the first time in nearly
six decades, the United States is on track
to become the world’s largest oil producer
as recently reported by The International
Energy Association. This development
further requires that exploration and
production companies have access to
clear, high resolution images to identify the
accumulation of hydrocarbon reservoirs to
accurately maximize drilling opportunities
and limit dry-hole risk. Our robust equipment
base and experienced crews have both the
capability and expertise to help our valued
clients responsibly unlock the resource
potential within these reservoirs.

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, 2012
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
(State or other jurisdiction of
incorporation or organization)

75-0970548
(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
Common Stock, $0.33 and 1⁄ 3 par value

Name of Exchange on Which Registered

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 Í

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 Í

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 Í

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 Í 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 ‘

Non-accelerated filer ‘ Smaller reporting company ‘

Accelerated filer Í

Indicate by check mark whether
No Í

Act). Yes ‘

(Do not check if a smaller reporting company)

the registrant

is a shell company (as defined in Rule 12b-2 of

the

As of March 31, 2012, the aggregate market value of Dawson Geophysical Company common stock, par value $0.33 1⁄ 3

per share, held by non-affiliates (based upon the closing transaction price on Nasdaq) was approximately $260,868,713.

On November 23, 2012, there were 8,031,369 shares of Dawson Geophysical Company common stock, $0.33 1⁄ 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 2013 Annual Meeting of Shareholders to be held on January 22,

2013 are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS

PART I

Item 1.

Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 2.

Item 3.

Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

PART II

Item 5. Market for Our Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . .

Item 6.

Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . .

Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 8.
Item 9.

Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . .

Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III

Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 13. Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . . .

Item 14.

Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

PART IV

Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

27
27

Index to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

F-1

Index to Exhibits

DAWSON GEOPHYSICAL COMPANY

FORM 10-K
For the Fiscal Year Ended September 30, 2012

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

including without

Statements other than statements of historical fact included in this Form 10-K that relate to forecasts,
estimates or other expectations regarding future events,
limitation, statements under
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business”
regarding technological advancements and our financial position, business strategy and plans and objectives of
our management for future operations, may be deemed to be forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the
“Exchange Act”). When used in this Form 10-K, words such as “anticipate,” “believe,” “estimate,” “expect,”
“intend” and similar expressions, as they relate to us or our management, identify forward-looking statements.
Such forward-looking statements are based on the beliefs of our management, as well as assumptions made by
and information currently available to management. Actual
results could differ materially from those
contemplated by the forward-looking statements as a result of certain factors, including but not limited to the
volatility of oil and natural gas prices, dependence upon energy industry spending, disruptions in the global
economy, industry competition, delays, reductions or cancellations of service contracts, high fixed costs of
operations, external factors affecting our crews such as weather interruptions and inability to obtain land access
rights of way, reduced utilization, the type of contracts we enter into, crew productivity, limited number of
customers, credit risk related to our customers, the availability of capital resources and operational disruptions.
See “Risk Factors” for more information on these and other factors. These forward-looking statements reflect our
current views with respect to future events and are subject to these and other risks, uncertainties and assumptions
relating to our operations, results of operations, growth strategies and liquidity. All subsequent written and oral
forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their
entirety by this paragraph. We assume no obligation to update any such forward-looking statements.

Item 1. BUSINESS

General

Part I

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. Over the past few years the focus of our
efforts has shifted between natural gas and oil-based exploration projects. Natural gas projects were our primary
focus until late 2008. Since that time, we have experienced a gradual shift in activity to oil exploration, which has
accelerated as oil prices have remained at a relatively high level in 2010, 2011 and 2012 while natural gas prices
have been relatively low during these periods. The majority of our crews are currently working in oil and liquids-
rich producing basins. Our clients rely on seismic data to identify areas where subsurface conditions are
favorable for the accumulation of hydrocarbons and to optimize the development and production of hydrocarbon
reservoirs. During fiscal 2012, substantially all of our revenues were derived from 3-D seismic data acquisition
operations.

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

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

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

Business Strategy

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

involves the collection of seismic data in a linear fashion thus generating a single plane of subsurface seismic
data. In recent years, the 2-D seismic method has been used as a regional evaluation tool in many of the limited
access shale basins, in particular the Marcellus Shale in the Appalachian Basin, in which we operated one small
channel count crew for a portion of fiscal 2012.

3-D seismic data are used in the exploration for new reserves and enable oil and gas companies to better
delineate existing fields and to augment their reservoir completion and management techniques. Benefits of
incorporating high resolution 3-D seismic surveys into exploration and development programs include reducing
drilling risk, decreasing oil and natural gas finding costs and increasing the efficiencies of reservoir location,
delineation, completion and management. In order to meet the requirements necessary to fully realize the benefits
of 3-D seismic data, there is an increasing demand for improved data quality with greater subsurface resolution.
We are prepared to meet such demands with the implementation of improved techniques and evolving
technology. In recent years, we have steadily increased the recording capacity of our crews by increasing channel
count and the number of energy source units we operate. These increases allow for a greater density of both
channels and energy sources in order to increase resolution and to improve operating efficiencies. We have also
utilized multi-component recording equipment on several projects in an effort to gain more information to help
our clients enhance their development of producing reservoirs. Multi-component recording involves the
collection of different seismic waves, including shear waves, which aids in reservoir analysis such as fracture
orientation and intensity in shales and more descriptive rock properties.

In recent years, we have experienced continued increases in recording channel capacity on a per crew or
project basis. This increase in channel count demand is driven by client needs and is necessary in order to
produce higher resolution images, increase crew efficiencies and undertake larger scale projects. Due to the
increase in demand for higher channel counts, we have continued our investments in additional channels. In
response to project-based channel requirements, we routinely deploy a variable number of channels on a variable
number of crews in an effort to maximize asset utilization and meet client needs. We believe we will realize the
benefit of increased channel counts and flexibility of deployment through increased crew efficiencies, higher
revenues and margins.

During fiscal 2011 and 2012, we purchased 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 redeployed on existing crews as needed, including on the additional two crews fielded during the second
quarter of fiscal 2011.

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

Utilizing electronic surveying equipment, survey personnel, who are either our employees or contract
companies, precisely locate the energy source and receiver positions from which the seismic data are collected.
We use vibrator energy sources which are mounted on vehicles, the majority of which weigh 62,000 pounds
each, to generate seismic energy, or we detonate dynamite charges placed in 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 169 vibrator energy source units and over 167,000 recording channels. We also currently
own eighteen central recording systems. Of the eighteen recording systems we owned at September 30, 2012, six
are Geospace Technologies GSR cable-less recording systems, eight are ARAM ARIES cable-based recording
systems and four 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.

At fiscal year-end 2012, we operated fourteen land-based seismic data acquisition crews. Each crew consists
of approximately forty to one hundred technicians, twenty-five or more vehicles with off-road capabilities, up to
100,000 geophones, a seismic recording system, energy sources, electronic cables and a variety of other
equipment. Our equipment may be configured on our crews in various combinations to meet the demands of
specific survey designs.

Of the fourteen data acquisition crews in operation at September 30, 2012, five used GSR recording
systems, six used ARAM recording systems, and three used RSR recording systems. All of our crews utilize
either vibrator energy sources or dynamite energy sources. While the number of recording systems we own is in
excess of the number needed to field our current level of data acquisition crews, we maintain the excess
equipment to provide additional operational flexibility and to allow us to quickly deploy additional recording
channels and energy source units as needed to respond to client demand and clients’ desire for improved data
quality with greater subsurface images.

Client demand for more recording channels continues to increase as the industry strives for improved data
quality with higher resolution subsurface images. We believe this trend will continue and that our ability to
deploy a large number of recording channels and multiple energy source units provides us with the competitive
advantages of operational versatility and increased productivity, in addition to improved data quality.

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

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

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

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

Equipment Acquisition and Capital Expenditures

We monitor and evaluate advances in geophysical technology and commit capital funds to purchase the
equipment we deem most effective to maintain our competitive position. Purchasing new assets and upgrading
existing capital assets requires a commitment to capital spending. During fiscal 2012, we invested $47,664,000
primarily on equipment and energy sources, including nineteen INOVA vibrator energy source units, 10,500
additional Geospace Technologies GSR single-channel recording units, 3,000 stations of Geospace Technologies
GSR three-channel units with three-component geophones and additional conventional geophones. These
purchases reflect our belief that the trend towards increased channel counts and energy sources in our industry
will continue. Our Board of Directors has approved an initial $40,000,000 capital budget for fiscal 2013 which
will be used to purchase nine INOVA AHV IV 364 vibrator energy sources units, increase channel count, make
technical improvements in various phases of our operations and meet maintenance capital requirements. We
believe that these additions will allow us to maintain our competitive position as we respond to client desire for
higher resolution subsurface images.

Clients

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

Our clients range from major oil and gas companies to small independent oil and gas operators and also
providers of multi-client data libraries. The services we provide to our clients vary according to the size and
needs of each client. During fiscal 2012, sales to our largest client, Chesapeake Energy Corporation, represented
21% of our revenue. The remaining balance of our fiscal 2012 revenue was derived from varied clients and none
represented 10% or more of our fiscal 2012 revenues. We anticipate that sales to Chesapeake will represent a
smaller percentage of our overall revenues during fiscal 2013.

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

Contracts

Our data acquisition services are conducted under master service contracts with our clients. These master
service contracts define certain obligations for us and for our clients. A supplemental agreement setting forth the
terms of a specific project, which may be cancelled by either party on short notice, is entered into for every data
acquisition project. The supplemental agreements are either “turnkey” agreements that provide for a fixed fee to
be paid to us for each unit of data acquired, or “term” agreements that provide for a fixed hourly, daily or
monthly fee during the term of the project or projects. Turnkey agreements generally provide us more profit
potential, but involve more risks because of the potential of crew downtime or operational delays. We attempt to
negotiate on a project-by-project basis some level of weather downtime protection within the turnkey
agreements. Under the term agreements, we forego an increased profit potential in exchange for a more
consistent revenue stream with improved protection from crew downtime or operational delays.

We operate under both turnkey and term supplemental agreements. The percentage of revenues derived
from turnkey contracts has grown in the past few years from approximately half of our revenues in fiscal 2008 to
in excess of three-quarters of our revenues in fiscal 2012. Currently, most of our projects are operated under
turnkey agreements. However, in the first quarter of fiscal 2013 we have observed an increase in inquiries and
requests for term agreements.

Competition

The acquisition and processing of seismic data for the oil and natural gas industry is a highly competitive
business in the United States. Contracts for such services generally are awarded on the basis of price quotations,
crew experience and availability of crews to perform in a timely manner, although factors other than price, such
as crew safety, performance history and technological and operational expertise, are often determinative. Our
competitors include companies with financial resources that are significantly greater than our own as well as
companies of comparable and smaller size. Our primary competitors are CGG Veritas, Geokinetics Inc., Global
Geophysical Services, Tidelands Geophysical Company and TESLA Exploration. In addition, the barriers to
entry in the seismic industry are not prohibitive, and it would not be difficult for seismic companies outside of
the United States to enter the United States market and compete with us.

Employees

As of September 30, 2012, we employed approximately 1,452 persons, of which 1,295 were engaged in
providing energy sources and acquiring data. With respect to the remainder of our employees, ten are engaged in
data processing, sixty-eight are administrative personnel, sixty-five are engaged in equipment maintenance and
transport and fourteen are officers. Of the employees listed above, nine are geophysicists. Our employees are not
represented by a labor union. We believe we have good relations with our employees.

Available Information

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

Item 1A. RISK FACTORS

An investment in our common stock is subject to a number of risks, including those discussed below. You
should carefully consider these discussions of risk and the other information included in this Form 10-K.
Although the risks described below are the risks that we believe are material to our business, they are not the
only risks that could affect our business. If any of the following events were to occur, our business, financial
condition or results of operations could be materially adversely affected.

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

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

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

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

include:

•

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

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

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

the worldwide political, military and economic conditions;

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

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

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

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

technological advances affecting energy exploration, production and consumption;

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

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.”

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

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

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

The acquisition and processing of seismic data for the oil and natural gas industry is a highly competitive
business in the United States. Some of our competitors have financial resources that are significantly greater than
our own. Additionally, the seismic data acquisition business is extremely price competitive and has a history of
periods in which seismic contractors bid jobs below cost and therefore adversely affect industry pricing. Many
contracts are awarded on a bid basis, which may further increase competition based primarily on price. In
addition, the barriers to entry in the seismic industry are not prohibitive, and it would not be difficult for seismic
companies outside of the United States to enter the United States market and compete with us. Competition from
these and other competitors could result in downward pricing pressure and the loss of market share. See
“Business — Competition.”

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

Our order book reflects client commitments at levels we believe are sufficient to maintain operations on our
existing crews for the indicated periods. However, our clients can delay, reduce or cancel their service contracts
with us on short notice. In addition, the timing of the completion of projects and when projects are awarded and
contracted for is also uncertain. As a result, our order book as of any particular date may not be indicative of
actual demand and revenues for any succeeding fiscal period. See “Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Overview.”

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

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

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

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

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

Our seismic data acquisition operations could be adversely affected by inclement weather conditions.
Delays associated with weather conditions could adversely affect our results of operations. For example, weather
delays could affect our operations on a particular project or an entire region and could lengthen the time to
complete data acquisition projects. In addition, even if we negotiate weather protection provisions in our
contracts, we may not be fully compensated by our clients for the delay caused by the inclement weather. Delays
from adverse weather conditions have particularly affected our results of operations in past periods and are likely
to affect our results in future periods. See “Business — Contracts.”

Our operations are subject to delays related to obtaining land access rights from third parties which could
affect our results of operations.

Our seismic data acquisition operations could be adversely affected by our inability to obtain timely right of
way usage from both public and private land and/or mineral owners. We cannot begin surveys on property
without obtaining permits from governmental entities as well as the permission of the private landowners who
own the land being surveyed. In recent years, it has become more difficult, costly and time-consuming to obtain
access rights of way as drilling activities have expanded into more populated areas. Additionally, while
landowners generally are cooperative in granting access rights, some have become more resistant to seismic and
drilling activities occurring on their property. In addition, governmental entities do not always grant permits
within the time periods expected. Delays associated with obtaining such rights of way have negatively affected
our results of operations in past periods and may affect our results in future periods. See “Business — Data
Acquisition.”

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

Our revenue is determined, in part, by the contract price we receive for our services, the level of utilization
of our fourteen 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 or in obtaining land access rights, over which we have no control. If our crews encounter
operational difficulties or delays on any data acquisition survey, our results of operations may vary, and in some
cases, may be adversely affected.

In fiscal 2012, most of our projects were performed on a turnkey basis for which we were paid a fixed price
for a defined scope of work or unit of data acquired. The revenue, cost and gross profit realized under our
turnkey contracts can vary from our estimates because of changes in job conditions, variations in labor and
equipment productivity or because of the performance of our subcontractors. Turnkey contracts may also cause
us to bear substantially all of the risks of business interruption caused by external factors over which we may
have no control, such as weather, obtaining land access rights, crew downtime or operational delays. These
in reducing our profitability. See
variations, delays and risks inherent
“Business — Contracts.”

in turnkey contracts may result

A limited number of customers operating in a single industry account for a significant portion of our
revenues, and the loss of one of these customers could adversely affect our results of operations; we bear
the risk if any of our clients become insolvent and fail to pay amounts owed to us, so any failure to pay by
these clients could harm our results of operations.

We derive a significant amount of our revenues from a relatively small number of oil and gas exploration
and development companies. Although our ten largest customers in fiscal 2012 and 2011 have varied, these
customers accounted for approximately 67% and 78% of our total revenue for these respective periods. For the
year ended September 30, 2012, our largest client represented approximately 21% of total revenues. If this client,
or any of our other significant clients, were to terminate their contracts or fail to contract for our services in the
future because they are acquired, alter their exploration or development strategy, experience financial difficulties
or for any other reason, our results of operations could be adversely affected. See “Business — Clients.”

We bear the credit risk if any of our clients become insolvent and fail to pay amounts owed to us. Although
we perform ongoing credit evaluations of our customers’ financial conditions, we generally require no collateral
from our customers. Some of our clients have experienced financial difficulties in the past and even filed
bankruptcy while others may do so in the future. It is possible that one or more of our clients will become
financially distressed, which could cause them to default on their obligations to us and could reduce the client’s
future need for seismic services provided by us. Our concentration of customers may also increase our overall
exposure to these credit risks. Our inability to collect our accounts receivable could have a materially adverse
effect on our results of operations. In addition, from time to time, we experience contractual disputes with our

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

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

Our continued success depends upon attracting and retaining highly skilled professionals and other technical
personnel. A number of our employees are highly skilled scientists and highly trained technicians, and our failure
to continue to attract and retain such individuals could adversely affect our ability to compete in the seismic
services industry. We may experience significant competition for these skilled and technically knowledgeable
personnel, particularly during periods of increased demand for seismic services. None of our employees are
under employment contracts, and we have no key man insurance.

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

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

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

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

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
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.

losses,

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

We could be subject to personal injury or real property damage claims in the normal operation of our
business. Such claims may not be covered under the indemnification provisions in our master service agreements
to the extent that the damage was due to our or our subcontractors’ negligence, gross negligence or intentional
misconduct.

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

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

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

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

Our operations are subject to a variety of federal, state and local laws and regulations, including laws and
regulations relating to protection of the environment and archeological sites. We are required to expend financial
and managerial resources to comply with such laws and related permit requirements in our operations, and we
anticipate that we will continue to be required to do so in the future. The fact that such laws or regulations change
frequently makes it impossible for us to predict the cost or impact of such laws and regulations on our future
operations. The adoption of laws and regulations that have the effect of reducing or curtailing exploration and

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

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

In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse
gases” (GHG) (including carbon dioxide and methane) may be contributing to global climate change, legislative
and regulatory measures to address the concerns are in various phases of discussion or implementation at the
national and state levels. At least one-third of the states, either individually or through multi-state regional
initiatives, have already taken legal measures intended to reduce GHG emissions, primarily through the planned
development of GHG emission inventories and/or GHG cap and trade programs.

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

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

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells.
Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock
formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic
fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have
been initiated to require or make more stringent the permitting and compliance requirements for hydraulic
fracturing operations. At the federal level, a bill was introduced in Congress in March 2011 entitled, the
“Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal
Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If 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 recently begun to operate in Canada. Conducting business in Canada subjects us to foreign
currency exchange rate risk. We do not hold or issue foreign currency forward contracts, option contracts or other
derivative financial instruments for speculative purposes or to mitigate the currency exchange rate risk. If our
operations in Canada are successful and the amount of business we do there grows, our results of operations and
our cash flows could be impacted by changes in foreign currency exchange rates.

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

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

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

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

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 2. PROPERTIES

Our principal facilities are summarized in the table below.

Location

Owned or
Leased

Purpose

Building Area
Square Feet

Midland, TX . . . . . . . . . . . . . . . . . . .

Leased

Executive offices and data

Midland, TX . . . . . . . . . . . . . . . . . . .

Owned

processing . . . . . . . . . . . . . . . .
Field office . . . . . . . . . . . . . . . . . .
Equipment fabrication facility
Maintenance and repairs shop

29,960
61,402

We have operating leases for domestic office space in Midland, Houston, Denver, Oklahoma City and

Pittsburgh and foreign office space in Calgary, Canada.

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

December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

High

Low

$31.90
$50.81
$47.02
$42.23
$40.18
$40.76
$34.57
$26.31

$24.16
$30.50
$29.53
$22.25
$21.57
$32.92
$20.29
$20.20

As of November 23, 2012, the market price for our common stock was $22.64 per share, and we had 154

common stockholders of record, as reported by our transfer agent.

We have not paid cash dividends on our common stock since becoming a public company and have no plans

to do so in the foreseeable future.

The following table summarizes certain information regarding securities authorized for issuance under our
equity compensation plan as of September 30, 2012. See information regarding material features of the plan in
Note 7, “Stock-Based Compensation” to the Consolidated Financial Statements included herein.

Equity Compensation Plan Information

Plan Category

Number of
Securities to
be Issued
Upon Exercise
of Outstanding
Options

(a)

Equity compensation plan approved

by security holders . . . . . . . . . . . . .

125,550

Equity compensation plans not

approved by security holders . . . . .

—

Total . . . . . . . . . . . . . . . . . . . . . . . . . .

125,550

Number of
Securities Remaining
Available for
Future Issuance
Under the Equity
Compensation Plan
(Excluding Securities
Reflected in
Column (a))

(c)

352,497

—

352,497

Weighted-Average Exercise
Price of
Outstanding Options

(b)

$18.91

—

$18.91

Performance Graph

The following graph compares the cumulative 5-year total return attained by shareholders on the Company’s
common stock relative to the cumulative total returns of the S&P 500 index and the PHLX Oil Service Sector
index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common
stock and in each of the indexes on 9/30/2007, and its relative performance is tracked through 9/30/2012.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Dawson Geophysical Company, the S&P 500 Index, and the PHLX Oil Service Sector
Index

$120

$100

$80

$60

$40

$20

9/07

9/08

9/09

9/10

9/11

9/12

Dawson Geophysical Company

S&P 500

PHLX Oil Service Sector

*$100 invested on 9/30/07 in stock or index, including reinvestment of dividends.
Fiscal year ending September 30.

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,

2012

2011

2010

2009

2008

Operating revenues . . . . . . . . . . . . . . .
Net income (loss) (1) . . . . . . . . . . . . .
Basic income (loss) per common

$319,274
$ 11,113

(In thousands, except per share amounts)
$243,995
$205,272
$333,279
$ 10,222
$ (9,352)
$ (3,246)

$324,926
$ 35,007

share . . . . . . . . . . . . . . . . . . . . . . . .

1.42

(0.42)

(1.20)

1.31

4.57

Weighted average equivalent

common shares outstanding . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . .
Revolving line of credit
. . . . . . . . . . .
Current maturities of notes payable
and obligations under capital
leases . . . . . . . . . . . . . . . . . . . . . . .

Notes payable and obligations under

capital leases less current
maturities . . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . .

7,842
$279,175
$

7,810
$264,824

7,777
$235,076

7,807
$237,157

— $

7,669
$233,621
—

9,131

5,290

— $

—

$ 11,179
$200,949

$ 10,281
$188,163

— $

$
$190,225

— $

—
$185,960

$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”).

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

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

may cancel, delay or alter their service contracts on short notice and we continue to remain subject to land access
permit and weather delays, our current order book reflects commitment levels sufficient to maintain operation of
fourteen crews well into fiscal 2013. The majority of our crews are currently working in oil producing basins.
However, in recent years, we have experienced periods in which the 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 robust, we were able to negotiate more favorable contract terms during fiscal 2012.

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

Currently, most of our client contracts are turnkey contracts. The percentage of revenues derived from
turnkey contracts has grown in the past few years from approximately half of our revenues in fiscal 2008 to in
excess of three-quarters of our revenues in fiscal 2012. While turnkey contracts allow us to capitalize on
improved crew productivity, we also bear more risks related to weather and crew downtime. We expect the
percentage of turnkey contracts to remain high as we continue to expand our operations in the mid-continent,
western and southwestern regions of the United States in which turnkey contracts are more common. However,
in the first quarter of fiscal 2013 we have observed an increase in inquiries and requests for term contracts.

Over time, we have experienced continued increases in recording channel capacity on a per crew or project
basis. This increase in channel count demand is driven by client needs and is necessary in order to produce higher
resolution images, increase crew efficiencies and undertake larger scale projects. Due to the increase in demand
for higher channel counts, we have continued our investments in additional channels. In response to project-
based channel requirements, we routinely deploy a variable number of channels on a variable number of crews in
an effort to maximize asset utilization and meet client needs. We believe we will realize the benefit of increased
channel counts and flexibility of deployment through increased crew efficiencies, higher revenues and margins.

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

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

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

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

Fiscal 2012 Highlights

• EBITDA for the year-ended September 30, 2012 increased to $49,615,000 compared to $27,861,000 for

the same period of fiscal 2011, an increase of 78 percent;

• Net income for the year-ended September 30, 2012 increased to $11,113,000, or $1.42 earnings per share,

compared to a net loss of $3,246,000, or $0.42 loss per share, in fiscal 2011;

• Reported revenues of $319,274,000 for the year-ended September 30, 2012 compared to $333,279,000 for

the year-ended September 30, 2011;

• Revenues net of third-party reimbursable charges increased 13 percent in fiscal 2012 from fiscal 2011;

• Strengthened order book capable of sustaining fourteen data acquisition crews well into calendar 2013;

• Fiscal 2012 capital expenditures of approximately $47,664,000 compared to $59,380,000 in fiscal 2011;

• Purchased 10,500 single-channel Geospace GSR units, 3,000 GSR three-channel units with three
component geophones and 19 INOVA vibrator energy source units to increase recording capacity and
improve efficiency;

• Balanced portfolio of projects in the Eagle Ford Shale, Niobrara Shale, Bakken Shale, Marcellus Shale,

Permian Basin and Mississippi Lime;

• Approximately $78 million of working capital at September 30, 2012; and

• Awarded first contract in Canada for the deployment of the Company’s first Canadian data acquisition

crew during the 2012-2013 winter season.

Results of Operations

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

Operating Revenues. Our operating revenues decreased 4% to $319,274,000 in fiscal 2012 from
$333,279,000 in fiscal 2011. The revenue decrease in fiscal 2012 was primarily the result of a significant
decrease in third-party charges and is not indicative of declining operations. Third-party charges decreased 29%
in fiscal 2012 from fiscal 2011 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 the Company’s margins during fiscal 2012. Improved turnkey rates,
increased productivity, reduced third-party charges and reduced equipment rental and repair costs all contributed
to this improvement in margins.

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

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

Our total operating costs for fiscal 2012 were $302,673,000, a decrease of 10% from fiscal 2011 primarily

due to the factors described above.

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

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

Operating Revenues. Our operating revenues increased 62% to $333,279,000 in fiscal 2011 from
$205,272,000 in fiscal 2010. The revenue increase in fiscal 2011 was primarily the result of an increase in active
crew count during fiscal 2011 and higher utilization rates of the existing crews. Revenues in fiscal 2011
continued to include high third-party charges related to the use of helicopter support services, specialized survey
technologies and dynamite energy sources. Approximately one-half of the increase in revenues during 2011 was
due to the increase in these third-party charges. The sustained high level of these charges is driven by our
continued operations in areas with limited access in the Appalachian Basin, Oklahoma, East Texas and Arkansas.

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

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

We recognized $30,536,000 of depreciation expense in fiscal 2011 as compared to $27,126,000 in fiscal
2010. Depreciation expense increased 13% from fiscal 2010 to 2011 reflecting increased capital expenditures
during fiscal 2010 and 2011.

Our total operating costs for fiscal 2011 were $336,605,000, an increase of 53% from fiscal 2010 primarily

due to the factors described above.

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

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,

2012

2011

2010

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense (income), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$11,113
32,498
601
5,403

(in thousands)
$ (3,246)
30,536
132
439

$ (9,352)
27,126
—
(4,638)

EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$49,615

$27,861

$13,136

Reconciliation of EBITDA to Net Cash Provided by Operating Activities

Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . .
Changes in working capital and other items . . . . . . . . . . . . . . . . . . .
Noncash adjustments to income . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Years Ended September 30,

2012

2011

2010

$ 76,380
(24,949)
(1,816)

(in thousands)
$16,951
12,812
(1,902)

$ 6,244
8,731
(1,839)

EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 49,615

$27,861

$13,136

Liquidity and Capital Resources

Introduction. Our principal sources of cash are amounts earned from the seismic data acquisition services
we provide to our clients. Our principal uses of cash are the amounts used to provide these services, including
expenses related to our operations and acquiring new equipment. Accordingly, our cash position depends (as do
our revenues) on the level of demand for our services. Historically, cash generated from our operations along
with cash reserves and borrowings from commercial banks have been sufficient to fund our working capital
requirements, and to some extent, our capital expenditures.

Cash Flows. Net cash provided by operating activities was $76,380,000 for fiscal 2012 and $16,951,000 for
fiscal 2011. These amounts primarily reflect an increase in revenues and operating margins 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, 2012 represents approximately 20% of our total trade accounts receivables, which is
consistent with historical levels. We believe our allowance for doubtful accounts of $250,000 at September 30,
2012 is adequate to cover exposures related to our trade account balances.

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

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

Capital Expenditures. For fiscal year 2012, we made capital expenditures of $47,664,000, primarily to
purchase 10,500 Geospace Technologies GSR single-channel units, 3,000 Geospace Technologies GSR three-
channel units, additional geophones, nineteen INOVA AHV IV 364 vibrator energy sources units and meet
necessary maintenance capital requirements. These purchases reflect our belief that the trend towards increased
channel counts and energy sources in our industry will continue. Our Board of Directors has approved an initial
fiscal 2013 capital budget of $40,000,000, which will be used, in part, to purchase nine INOVA AHV IV 364
vibrator energy source units, while the remainder will be used to increase channel count, make technical
improvements in various phases of our operations and meet maintenance capital requirements. We believe that
our fiscal 2012 capital investments as well as our planned fiscal 2013 capital investments will allow us to
maintain our competitive position as we respond to client desire for higher resolution subsurface images.

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

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

Our revolving line of credit loan agreement is with Western National Bank. The agreement was renewed
June 2, 2011 under the same terms as the previous agreement and permits us to borrow, repay and reborrow,
from time to time until June 2, 2013, up to $20.0 million based on the borrowing base calculation as defined in
the agreement. Our obligations under this agreement are secured by a security interest in our accounts receivable,
equipment and related collateral. Interest on the facility accrues at an annual rate equal to either the 30-day
London Interbank Offered Rate (“LIBOR”), plus two and one-quarter percent, or the Prime Rate, minus three-
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, 2012 and December 5, 2012 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, 2012 or 2011.

We amended our credit loan agreement with Western National Bank on June 30, 2011 to add a new term
loan note (“Term Note”) provision, which provided $16,427,000 in financing for the purchase of Geospace
Technologies GSR equipment. The Term Note is repayable over a period of 36 months at $485,444 per month
plus any applicable interest. The Term Note bears interest at an annual rate equal to either the 30-day 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 with Western National Bank. The Second Term Note allows us to borrow from time to time up to
$15.0 million to purchase equipment. On July 5, 2012, we borrowed $9,346,000 under the Second Term Note to
purchase Geospace Technologies GSR recording equipment. The outstanding principal under the Second Term
Note will be amortized over 36 months. The Second Term Note bears interest at an annual rate equal to either the
30-day LIBOR, plus two and one-quarter percent, or the Prime Rate, minus three-quarters percent, as we direct
monthly, subject to an interest rate floor of 3.75%, and otherwise has the same terms as our revolving line of
credit. The Second Term Note is collateralized by a security interest in our accounts receivable, equipment and
related collateral and matures with all outstanding balances due on May 2, 2015.

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

The following table summarizes payments due in specific periods related to our contractual obligations with

initial terms exceeding one year as of September 30, 2012.

Payments Due by Period (in 000’s)

Contractual Obligations

Operating lease obligations (office space) . . . .
Capital lease obligations . . . . . . . . . . . . . . . . . .
Debt obligations . . . . . . . . . . . . . . . . . . . . . . . .

Total

$ 3,288
1,208
19,102

Within 1
Year

$ 865
415
8,716

$ 1,720
689
10,386

1-2 Years

3-5 Years

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$23,598

$9,996

$12,795

After 5
Years

$—
—
—

$—

$703
104
—

$807

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, 2012, we had no off-balance sheet arrangements.

Effect of Inflation

We do not believe that inflation has had a material effect on our business, results of operations or financial

condition during the past three fiscal years.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles
requires us to make certain assumptions and estimates that affect the reported amounts of assets and liabilities at
the date of our financial statements and the reported amounts of revenues and expenses during the reporting
periods. Because of the use of assumptions and estimates inherent in the reporting process, actual results could
differ from those estimates.

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

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

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

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

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

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

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

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

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

Recently Issued Accounting Pronouncements

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

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

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks arising from the use of financial instruments in the ordinary course
of business. These risks arise primarily as a result of potential changes to operating concentration 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 may subject 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, 2012 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, 2012, 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, 2012, cash and cash equivalents totaled $57,373,000.

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, 2012, our
disclosure controls and procedures were effective,
in all material respects, with regard to the recording,
processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, for
information required to be disclosed by us in the reports that we file or submit under the Exchange Act. Our
disclosure controls and procedures include controls and procedures designed to ensure that information required
to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our
management, including our President and Chief Executive Officer and our Executive Vice President, Secretary
and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

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

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting (as defined in Exchange
Act Rule 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended
September 30, 2012 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 22, 2013, which we expect to file with the Securities and
Exchange Commission within 120 days after September 30, 2012. 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

L. Decker Dawson . . . . . . . . . . . . . . . . . .
Stephen C. Jumper . . . . . . . . . . . . . . . . . .
C. Ray Tobias . . . . . . . . . . . . . . . . . . . . . .
Christina W. Hagan . . . . . . . . . . . . . . . . . .

James W. Thomas . . . . . . . . . . . . . . . . . . .
K.S. Forsdick . . . . . . . . . . . . . . . . . . . . . .

Age

92
51
55
57

58
61

Position

Chairman of the Board of Directors
President, Chief Executive Officer and Director
Executive Vice President, Chief Operating Officer
Executive Vice President, Secretary and Chief
Financial Officer
Executive Vice President, Chief Technical Officer
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.

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

Stephen C. Jumper. Mr. Jumper, a geophysicist, joined the Company in 1985, was elected Vice President of
Technical Services in September 1997 and was subsequently elected President, Chief Operating Officer and
Director in January 2001. In January 2006, Mr. Jumper was elected President, Chief Executive Officer and
Director. Prior to 1997, Mr. Jumper served the Company as manager of technical services with an emphasis on
3-D processing. Mr. Jumper has served the Permian Basin Geophysical Society as Second Vice President, 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 22, 2013, which we expect to file with the Securities and
Exchange Commission within 120 days after September 30, 2012.

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 22, 2013, which we expect to file with the
Securities and Exchange Commission within 120 days after September 30, 2012.

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 22, 2013, which we expect to file with the Securities and
Exchange Commission within 120 days after September 30, 2012.

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 22, 2013, which we expect to file with the Securities and
Exchange Commission within 120 days after September 30, 2012.

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-21 and

are incorporated by reference into Part II, Item 8:

Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity and Other Comprehensive Income (Loss)
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements

(2) Financial Statement Schedules.

The following financial statement schedule appears on page F-22 and is hereby incorporated by reference:

Schedule II — Consolidated Valuation and Qualifying Accounts for

the three years ended

September 30, 2012, 2011 and 2010.

All other 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 5th day of December, 2012.

DAWSON GEOPHYSICAL COMPANY

By: /s/ Stephen C. Jumper

Stephen C. Jumper
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/ L. Decker Dawson

L. Decker Dawson

/s/ Stephen C. Jumper

Stephen C. Jumper

/s/ Paul H. Brown

Paul H. Brown

/s/ Craig W. Cooper

Craig W. Cooper

/s/ Gary M. Hoover

Gary M. Hoover

/s/ Jack D. Ladd

Jack D. Ladd

/s/ Ted R. North

Ted R. North

/s/ Tim C. Thompson

Tim C. Thompson

/s/ Christina W. Hagan

Christina W. Hagan

Chairman of the Board of Directors

12-5-12

President, Chief Executive Officer and Director
(principal executive officer)

12-5-12

Director

Executive Vice President, Secretary and Chief
Financial Officer (principal financial and
accounting officer)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Financial Statements of Dawson Geophysical Company

Reports of Independent Registered Public Accounting Firm, dated December 5, 2012 . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets as of September 30, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended September 30, 2012, 2011 and 2010 . . . . . . . .
Consolidated Statements of Stockholders’ Equity and Other Comprehensive Income (Loss) for the years

ended September 30, 2012, 2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows for the years ended September 30, 2012, 2011 and 2010 . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statement Schedule:
Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended September 30, 2012,

Page

F-2
F-4
F-5

F-6
F-7
F-8

2011 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-22

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 sheets of Dawson Geophysical Company as of
September 30, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity and
other comprehensive income (loss), and cash flows for each of the years in the three-year period ended
September 30, 2012. In connection with our audits of the consolidated financial statements, we also have audited
financial statement Schedule II. These consolidated financial statements and financial statement schedule are the
responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated
financial statements and financial statement schedule 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 2011, and the results of its
operations and its cash flows for each of the years in the three-year period ended September 30, 2012, in
conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial
statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the effectiveness of Dawson Geophysical Company’s internal control over financial reporting as
of September 30, 2012, based on criteria established in Internal Control — Integrated Framework issued by the
Committee of Sponsoring Organizations of
report dated
December 5, 2012 expressed an unqualified opinion on the effectiveness of Dawson Geophysical Company’s
internal control over financial reporting.

the Treadway Commission (COSO), and our

Dallas, Texas
December 5, 2012

KPMG LLP

F-2

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, 2012, based on “criteria established in Internal Control — Integrated Framework issued by the
Committee of Sponsoring Organizations of
the Treadway Commission (COSO)”. 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, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audit also included 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, 2012, based on “criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission”.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of Dawson Geophysical Company as of September 30, 2012 and
2011, and the related consolidated statements of operations, stockholders’ equity and other comprehensive
income (loss), and cash flows for each of the years in the three-year period ended September 30, 2012, and the
related financial statement schedule, and our report dated December 5, 2012 expressed an unqualified opinion on
those consolidated financial statements and financial statement schedule.

Dallas, Texas
December 5, 2012

KPMG LLP

F-3

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED BALANCE SHEETS

September 30,
2012

September 30,
2011

Current assets:

ASSETS

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net of allowance for doubtful accounts of $250,000 and
$155,000 at September 30, 2012 and September 30, 2011, respectively . . .
Prepaid expenses and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 57,373,000
4,000,000

$ 26,077,000
—

53,719,000
762,000
1,925,000

86,716,000
4,254,000
1,236,000

Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

117,779,000

118,283,000

Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

326,030,000
(164,634,000)

302,647,000
(156,106,000)

Net property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

161,396,000

146,541,000

Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 279,175,000

$ 264,824,000

Current liabilities:

LIABILITIES AND STOCKHOLDERS’ EQUITY

Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities:

Payroll costs and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current maturities of notes payable and obligations under capital leases . . . .

$ 18,544,000

$ 18,732,000

1,802,000
6,425,000
3,467,000
9,131,000

1,436,000
9,230,000
9,616,000
5,290,000

Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

39,369,000

44,304,000

Long-term liabilities:

Notes payable and obligations under capital leases less current maturities . . .
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

11,179,000
27,678,000

10,281,000
22,076,000

Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

38,857,000

32,357,000

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, 8,031,369 and 7,910,885 shares issued and
outstanding at September 30, 2012 and September 30, 2011,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,677,000
93,224,000
105,048,000

2,637,000
91,591,000
93,935,000

Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

200,949,000

188,163,000

Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . .

$ 279,175,000

$ 264,824,000

See accompanying notes to the consolidated financial statements.

F-4

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating costs:

Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Income (loss) from operations . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense):

Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Income (loss) before income tax . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax (expense) benefit:

Years Ended September 30,

2012

2011

2010

$319,274,000

$333,279,000

$205,272,000

258,970,000
11,205,000
32,498,000

302,673,000
16,601,000

292,519,000
13,550,000
30,536,000

185,588,000
7,131,000
27,126,000

336,605,000
(3,326,000)

219,845,000
(14,573,000)

28,000
(629,000)
516,000

35,000
(167,000)
651,000

185,000
—
398,000

16,516,000

(2,807,000)

(13,990,000)

Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(490,000)
(4,913,000)

2,929,000
(3,368,000)

7,102,000
(2,464,000)

(5,403,000)

(439,000)

4,638,000

Net income (loss)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 11,113,000

$ (3,246,000) $ (9,352,000)

Basic income (loss) per common share . . . . . . . . . . . . . . . . . . . . .

Diluted income (loss) per common share . . . . . . . . . . . . . . . . . . .

1.42

1.40

(0.42) $

(1.20)

Weighted average equivalent common shares outstanding . . . . .

7,841,722

7,809,561

7,777,404

Weighted average equivalent common shares outstanding —

assuming dilution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7,931,593

7,809,561

7,777,404

See accompanying notes to the consolidated financial statements.

F-5

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE
INCOME (LOSS)

Common Stock

Number
of Shares

Amount

Additional
Paid-in
Capital

Accumulated
Other
Comprehensive
Income (Loss)

7,822,994

$2,608,000

$89,220,000

$ 18,000

Retained
Earnings

Total

$106,533,000
(9,352,000)

$198,379,000
(9,352,000)

Balance September 30, 2009 . . . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive loss net of tax:

Realization of losses on investment . . . .
Unrealized holding gains arising during
the period . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .

Income tax benefit

Other comprehensive loss . . . . . . . . . . . . .

Comprehensive loss for the period . . . . . . .
Stock-based compensation expense . . . . . .
Issuance of common stock as

(28,000)

3,000
11,000

(14,000)

1,398,000

compensation . . . . . . . . . . . . . . . . . . . . .

8,340

3,000

182,000

Issuance of restricted stock awards and

unearned compensation . . . . . . . . . . . . .
Exercise of stock options . . . . . . . . . . . . . .
Shares exchanged for taxes on stock-based
compensation . . . . . . . . . . . . . . . . . . . . .

Balance September 30, 2010 . . . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive loss net of tax:

Realization of losses on investment . . . .
. . . . . . . . . . . . . . . . .
Income tax benefit

Other comprehensive loss . . . . . . . . . . . . .

Comprehensive loss for the period . . . . . . .
Tax deficit resulting from share-based

compensation . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . .
Issuance of common stock as

compensation . . . . . . . . . . . . . . . . . . . . .
Forfeiture of restricted stock awards . . . . .
Shares exchanged for taxes on stock-based
compensation . . . . . . . . . . . . . . . . . . . . .
Exercise of stock options . . . . . . . . . . . . . .

Balance September 30, 2011 . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . .
Issuance of common stock as

compensation . . . . . . . . . . . . . . . . . . . . .
Exercise of stock options . . . . . . . . . . . . . .
Issuance of restricted stock awards and

84,100
250

28,000

(28,000)
4,000

(13,578)

(5,000)

(370,000)

7,902,106

2,634,000

90,406,000

4,000

(6,000)
2,000

(4,000)

(453,000)
1,485,000

184,000

(323,000)
292,000

6,479
(4,000)

(9,400)
15,700

2,000
(1,000)

(3,000)
5,000

7,910,885

2,637,000

91,591,000

—

1,245,000

7,234
9,750

3,000
3,000

241,000
181,000

unearned compensation . . . . . . . . . . . . .

103,500

34,000

(34,000)

(14,000)

(9,366,000)
1,398,000

185,000

—
4,000

(375,000)

97,181,000
(3,246,000)

190,225,000
(3,246,000)

(4,000)

(3,250,000)

(453,000)
1,485,000

186,000
(1,000)

(326,000)
297,000

93,935,000
11,113,000

188,163,000
11,113,000
1,245,000

244,000
184,000

—

Balance September 30, 2012 . . . . . . . . . .

8,031,369

$2,677,000

$93,224,000

—

$105,048,000

$200,949,000

See accompanying notes to the consolidated financial statements.

F-6

DAWSON GEOPHYSICAL COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended September 30,

2012

2011

2010

CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 11,113,000

$ (3,246,000) $ (9,352,000)

Adjustments to reconcile net income (loss) to net cash provided by operating

activities:
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncash compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Change in current assets and liabilities:

32,498,000
1,489,000
4,913,000
327,000
192,000

30,536,000
1,671,000
3,368,000
231,000
(516,000)

27,126,000
1,583,000
2,464,000
256,000
(343,000)

Decrease (increase) in accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease (increase) in prepaid expenses and other assets . . . . . . . . . . . . . . .
(Decrease) increase in accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease in accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Decrease) increase in deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . .

32,670,000
3,359,000
(1,593,000)
(2,439,000)
(6,149,000)

(30,613,000)
3,402,000
3,628,000
(922,000)
9,412,000

(17,876,000)
(37,000)
6,181,000
(1,732,000)
(2,026,000)

Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

76,380,000

16,951,000

6,244,000

CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures, net of noncash capital expenditures summarized

below in noncash investing and financing activities . . . . . . . . . . . . . . . . .
Proceeds from maturity of short-term investments . . . . . . . . . . . . . . . . . . . .
Acquisition of short-term investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Partial proceeds on fire insurance claim . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(44,832,000)
500,000
(4,500,000)
252,000
—

(58,550,000)
22,500,000
(2,500,000)
741,000
1,392,000

(18,835,000)
20,000,000
(14,964,000)
434,000
—

Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(48,580,000)

(36,417,000)

(13,365,000)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal payments on notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Principal payments on capital lease obligations . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . .

9,346,000
(5,814,000)
(220,000)
184,000

16,427,000
(856,000)
—
297,000

Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3,496,000

15,868,000

—
—
—
4,000

4,000

Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . .
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . .

31,296,000
26,077,000

(3,598,000)
29,675,000

(7,117,000)
36,792,000

CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . . . . .

$ 57,373,000

$ 26,077,000

$ 29,675,000

SUPPLEMENTAL CASH FLOW INFORMATION:

Cash paid for interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash received for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

618,000
$
$
262,000
$ 3,258,000

115,000
$
$
509,000
$ 7,366,000

—
$
$
839,000
$ 8,125,000

NONCASH INVESTING AND FINANCING ACTIVITIES:

Accrued purchases of property and equipment
. . . . . . . . . . . . . . . . . . . . . . .
Equipment purchase through asset trade in . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 1,405,000
$
$ 1,427,000
$

$
— $
$
— $

830,000

$ 1,127,000
— $ 2,260,000
—
— $
3,000
— $

See accompanying notes to the consolidated financial statements

F-7

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 in the Consolidated
Statements of Operations for the years ended September 30, 2012, 2011 or 2010.

F-8

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
the fair market value of the related assets. Assets under capital leases are depreciated using the straight-line
method over the initial lease term.

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 customer 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, customers 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 and
restricted stock, 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
including
for recording income taxes requires judgment regarding assumptions and the use of estimates,

F-9

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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, 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, 2012. There
were no outstanding short-term investments at September 30, 2011.

3. Fair Value of Financial Instruments

At September 30, 2012 and 2011, the Company’s financial instruments included cash and cash equivalents,
trade and other receivables, other current assets, accounts payable, other current liabilities and the Term Note. At
September 30, 2012, the Company’s financial instruments also included short-term investments in certificates of
deposit and the Second Term Note. Due to the short-term maturities of cash and cash equivalents, short-term
investments in certificates of deposit, 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
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.

4. Property, Plant and Equipment

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

September 30,

2012

2011

Useful Lives

Land, building and other . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . .
Recording equipment
Line clearing equipment . . . . . . . . . . . . . . . . . . .
Vibrator energy sources . . . . . . . . . . . . . . . . . . .
Vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

8,641,000
206,642,000
913,000
76,813,000
32,429,000
592,000

7,532,000
199,347,000
—
65,175,000
30,337,000
256,000

3 to 40 years
5 to 10 years
5 years
5 to 15 years
1.5 to 10 years
—

Less accumulated depreciation . . . . . . . . . . . . . .

326,030,000
(164,634,000)

302,647,000
(156,106,000)

Net property, plant and equipment . . . . . . . . . . .

$ 161,396,000

$ 146,541,000

(a) Other represents accumulated costs associated with equipment fabrication and modification not yet

completed.

F-10

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5. Supplemental Consolidated Balance Sheet Information

Accounts receivable consist of the following at September 30, 2012 and 2011:

September 30,

2012

2011

Trade and accrued trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued receivable for workers’ compensation stop loss policy . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$53,268,000
(250,000)
623,000
78,000

$82,676,000
(155,000)
3,852,000
343,000

Total accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$53,719,000

$86,716,000

Prepaid expenses and other assets consist of the following at September 30, 2012 and 2011:

September 30,

2012

2011

Prepaid expenses and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$762,000
—

$ 943,000
3,311,000

Total prepaid expenses and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . .

$762,000

$4,254,000

Other current liabilities consist of the following at September 30, 2012 and 2011:

Accrued self-insurance reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income and franchise taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other accrued expenses and current liabilities . . . . . . . . . . . . . . . . . . . . . .

$2,181,000
1,096,000
3,148,000

$5,567,000
897,000
2,766,000

Total other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$6,425,000

$9,230,000

September 30,

2012

2011

6. Debt

The Company’s revolving line of credit loan agreement is with Western National Bank. The agreement was
renewed June 2, 2011 under the same terms as the previous agreement. The agreement permits the Company to
borrow, repay and reborrow, from time to time until June 2, 2013, up to $20.0 million based on the borrowing base
calculation as defined in the agreement. 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, 2012 and December 5, 2012 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, 2012 or September 30, 2011.

The Company amended its credit loan agreement with Western National Bank on June 30, 2011 to add the
Term Note provision, under which the Company obtained $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. Interest on the Term Note accrues at an annual rate equal to either the 30-day

F-11

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. The fair value of the Term
Note approximates its carrying value at September 30, 2012 due to the fact that the interest rate on the Term Note
is reset each month based on the prevailing market interest rate.

On May 11, 2012, the Company entered into the Second Term Note under its credit loan agreement with
Western National Bank. 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 will be 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.
The fair value of the Second Term Note approximates its carrying value at September 30, 2012 due to the fact that
the interest rate on the Second Term Note is reset each month based on the prevailing market interest rate.

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 February 2017. At September 30, 2012, the Company had leased 42
vehicles under these capital leases.

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

September 30,
2012

September 30,
2011

Term Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Term Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revolving line of credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Obligations under capital leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$10,281,000
8,821,000
—
1,208,000

$15,571,000
—
—
—

Less current maturities of notes payable and obligations under capital

leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(9,131,000)

(5,290,000)

$20,310,000

$15,571,000

$11,179,000

$10,281,000

The aggregate maturities of the notes payable and obligations under capital leases at September 30, 2012 are

as follows:

October 2012 – September 2013
October 2013 – September 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
October 2014 – September 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
October 2015 – September 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
October 2016 – September 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$9,131,0000
8,530,000
2,545,000
73,000
31,000

$20,310,000

F-12

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Stock-Based Compensation

At September 30, 2012, the Company had one stock-based compensation plan. The awards outstanding

under this plan and the associated accounting treatment are discussed below.

In fiscal 2007, the Company adopted the Dawson Geophysical Company 2006 Stock and Performance
Incentive Plan (“the Plan”). The Plan provides 750,000 shares of authorized but unissued common stock of the
Company which may be awarded to officers, directors, employees and consultants of the Company in various
forms including options, grants, restricted stock grants 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 over 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 optionee 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, 2012, as well as activity during

the year then ended is presented below.

Balance as of September 30, 2011 . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Number of
Optioned
Shares

135,300
—
(9,750)
—

Balance as of September 30, 2012 . . . . . . . . . .

125,550

Exercisable as of September 30, 2012 . . . . . . .

87,800

Weighted
Average
Exercise
Price

$18.91
—
18.91
—

$18.91

Weighted
Average
Remaining
Contractual
Term in Years

Aggregate
Intrinsic
Value ($000)

$173

$797

$558

6.17

No options were granted during fiscal 2012, 2011 or 2010. The total intrinsic value of options exercised
during fiscal 2012, 2011 and 2010 was $173,000, $318,000 and $1,000, respectively. The total fair value of
options vested during fiscal 2012, 2011 and 2010 was $362,000, $362,000 and $364,000, respectively.

A summary of the status of the Company’s nonvested stock option awards as of September 30, 2012 and

changes during the year then ended is presented below.

Nonvested option awards outstanding September 30, 2011 . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested option awards outstanding September 30, 2012 . . . . . . .

75,500
—
(37,750)
—
37,750

$9.59
—
9.59
—
$9.59

Number of
Nonvested
Share Awards

Weighted Average
Grant Date
Fair Value

F-13

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Outstanding options at September 30, 2012 expire in December 2018 and have an exercise price of $18.91.
As of September 30, 2012, there was approximately $61,000 of unrecognized compensation cost related to
nonvested stock option awards to be recognized over a weighted average period of 0.17 years.

Stock options issued under the Company’s 2006 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, 2012, 2011 and 2010,
there were no excess tax benefits from disqualifying dispositions.

Cash received from option exercises under all share-based payment arrangements during the years ended

September 30, 2012, 2011 and 2010 was $184,000, $297,000 and $4,000, respectively.

The Company recognized compensation expense associated with stock option awards of $362,000,
$362,000 and $363,000 in fiscal 2012, 2011 and 2010, respectively. This amount is included in operating or
general and administrative expense as appropriate in the Consolidated Statements of Operations.

Stock Awards:

The Company granted 103,500 and 84,100 shares of restricted stock to employees in fiscal 2012 and 2010,
respectively. The weighted average grant date fair value of restricted stock awards in fiscal 2012 and 2010 was
$23.55 and $23.33, respectively. The fair value of the restricted stock granted equals the market price on the
grant date and vests after three years. There were no restricted stock grants in 2011.

A summary of the status of the Company’s nonvested restricted stock awards as of September 30, 2012 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, 2011 . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Nonvested restricted shares outstanding September 30, 2012 . . . . .

81,100
103,500
—
—

184,600

$23.33
$23.55
$ —
$ —

$23.45

The Company’s tax benefit with regards to restricted stock awards is consistent with the tax election of the
recipient of the award. No elections under IRC Section 83(b) have been made for the restricted stock awards
granted by the Company in fiscal 2012. As a result, the compensation expense recorded for restricted stock
resulted in a deferred tax asset for the Company equal to the tax effect of the amount of compensation expense
recorded.

The Company recognized compensation expense related to restricted stock awards of $883,000, $1,123,000
and $1,035,000 in fiscal 2012, 2011 and 2010, respectively. This amount is included in operating or general and
administrative expense as appropriate in the Consolidated Statements of Operations. As of September 30, 2012,
there was approximately $2,603,000 of unrecognized compensation cost related to nonvested restricted stock
awards granted. This cost is expected to be recognized over a weighted average period of 2.32 years.

The Company granted common shares with immediate vesting to outside directors and employees in fiscal

years 2012, 2011 and 2010:

Number of
Shares Granted

Weighted Average
Grant Date
Fair Value

2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7,234
6,479
8,340

$33.64
$28.69
$22.11

F-14

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company recognized expense of $244,000, $186,000 and $185,000 in fiscal 2012, 2011 and 2010,

respectively, as well as the related tax benefit associated with these awards.

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 2012, 2011 and 2010, 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 2012, 2011 and 2010 were approximately $1,521,000, $1,366,000 and $1,270,000, respectively.

9. Advertising Costs

Advertising costs are charged to expense as incurred. Advertising costs totaled $340,000, $370,000 and

$256,000 during the fiscal years ended September 30, 2012, 2011 and 2010, respectively.

10.

Income Taxes

The Company recorded income tax expense in the current year of $5,403,000, as compared to income tax

expense of $439,000 in 2011 and income tax benefit of $4,638,000 in 2010.

Income tax expense (benefit) from operations:

Year Ended September 30,

2012

2011

2010

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current federal
Current state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ (10,000)
500,000
4,737,000
176,000

$(3,167,000)
238,000
3,920,000
(552,000)

$(7,342,000)
240,000
2,817,000
(353,000)

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$5,403,000

439,000

$(4,638,000)

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,

2012

2011

2010

Tax expense (benefit) computed at statutory rate

of 35% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in valuation allowance . . . . . . . . . . . . . . . . . . . . .
State income tax expense (benefit), net of federal tax . . .
Transaction costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 5,781,000
—
433,000
(1,353,000)
542,000

$ (982,000)
(19,000)
(284,000)
1,353,000
371,000

$(4,896,000)
(39,000)
(82,000)
—
379,000

Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . .

$ 5,403,000

$ 439,000

$(4,638,000)

F-15

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,

2012

2011

Deferred tax assets:

Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Workers’ compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax net operating loss (NOL) carry forward . . . . . . . . . . . . . .
Federal tax NOL carry forward . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Self-insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Canadian start-up costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AMT credit carry forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 1,265,000
579,000
270,000
691,000
12,776,000
298,000
153,000
177,000
210,000

550,000
258,000
331,000
853,000
13,625,000
298,000
—
177,000
262,000

Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

16,419,000

16,354,000

Deferred tax liabilities:

Property and equipment

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(42,172,000)

(37,194,000)

Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(42,172,000)

(37,194,000)

Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$(25,753,000)

$(20,840,000)

Current portion of net deferred tax asset/liability . . . . . . . . . . . . . . . .
Non-current portion of net deferred tax asset/liability . . . . . . . . . . . . .

$ 1,925,000
(27,678,000)

$ 1,236,000
(22,076,000)

Total net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$(25,753,000)

$(20,840,000)

At September 30, 2012,

the Company had a gross NOL for U.S. federal

income tax purposes of
approximately $36,502,000. This NOL expires in 2031. The Company will carry forward the net federal NOL of
approximately $12,776,000. The Company also had net state NOLs that will affect state taxes of approximately
$691,000 at September 30, 2012. 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. The Company believes, based on past
levels of income, it is more likely than not that the results of future operations will generate sufficient taxable
income in which to realize these deferred tax assets. As such, no valuation allowance was considered necessary
related to the federal or state NOLs.

At September 30, 2011, the Company released all of the valuation allowance held at September 30, 2010
related to the Company’s deferred tax assets for capital loss carry forwards. The Company has no valuation
allowances as of September 30, 2012.

The following presents a roll forward of the Company’s unrecognized tax benefits:

September 30,

2012

2011

Balance at beginning of fiscal year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expiration of statutes of limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$ 161,000
(161,000)

$235,000
(74,000)

Balance at end of fiscal year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

— $161,000

As of September 30, 2012, the Company did not recognize any liabilities for unrecognized tax benefits. All
of the liabilities for unrecognized tax benefits 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 2012 or 2011.

F-16

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company’s practice is to recognize interest and penalties related to unrecognized tax benefits in income
tax expense. In fiscal years 2012 and 2011, the Company’s net accrued interest and penalties decreased by
approximately $98,000 and $11,000, respectively.

11.

Income (loss) per Common Share

Basic income (loss) per share is computed by dividing the net income (loss) for the period by the weighted
average number of common shares outstanding during the period. Diluted income (loss) per share is computed by
dividing the net income (loss) for the period by the weighted average number of common shares and common
share equivalents outstanding during the period.

The following table sets forth the computation of basic and diluted income (loss) per common share.

2012

2011

2010

Numerator:

Net income (loss) and numerator for basic and diluted income
(loss) per common share — income available to common
shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Denominator:

$11,113,000

$(3,246,000) $(9,352,000)

Denominator for basic income (loss) per common share-weighted

average common shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7,841,722

7,809,561

7,777,404

Effect of dilutive securities-employee stock options and restricted

stock grants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

89,871

—

Denominator for diluted income (loss) per common share-adjusted
weighted average common shares and assumed conversions . . .

Basic income (loss) per common share . . . . . . . . . . . . . . . . . . . . . . . .

Diluted income (loss) per common share . . . . . . . . . . . . . . . . . . . . . . .

7,931,593

7,809,561

7,777,404

1.42

1.40

(0.42) $

(1.20)

The Company had a net loss in 2011 and 2010; therefore the denominator for diluted loss per common share

is the same as the denominator for basic loss per common share for these periods.

The following weighted average numbers of certain securities have been excluded from the calculation of

diluted income (loss) per common share, as their effects would be anti-dilutive.

Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

— 140,487
105,655

46,273

151,710
54,397

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

46,273

246,142

206,107

2012

2011

2010

12. Major Customers

The Company operates in only one business segment, contract seismic data acquisition and processing
services. The major customers in fiscal 2012, 2011 and 2010 have varied. Sales to these customers, as a
percentage of operating revenues that exceeded 10%, were as follows:

2012

2011

2010

A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —

21% 27% 32%

24% —

F-17

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 domestic office space in Midland, Houston, Denver,

Oklahoma City and Pittsburgh and foreign office space in Calgary, Canada.

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, 2012.

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) . . . . .

$3,288

$865

$1,720

$703

$—

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 $805,000, $717,000
and $619,000 for fiscal 2012, 2011 and 2010, respectively.

As of November 30, 2012, the Company had unused letters of credit totaling approximately $1,580,000. 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’
compensation claims after October 1, 2011. The unused letters of credit outstanding at November 30, 2012 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

F-18

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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
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

F-19

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

changes certain fair value measurement principles and enhances disclosure requirements, particularly for Level 3
fair value measurements. The enhanced disclosures and fair value measurement principles were effective for the
Company as of January 1, 2012. The adoption of this guidance did not have a material impact on the Company’s
financial statements.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of
Comprehensive Income,” to require an entity to present the total of comprehensive income, the components of
net income, and the components of other comprehensive income either in a single continuous statement of
comprehensive income or in two separate but consecutive statements. ASU 2011-05 eliminates the option to
present the components of other comprehensive income as part of the statement of equity. This update does not
change what items are reported in other comprehensive income or the requirement to report reclassification of
items from other comprehensive income to net income. However, in December 2011, the FASB issued ASU
No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the
Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting
Standards Update No. 2011-05,” that deferred the specific requirement within ASU 2011-05 to present on the
face of the financial statements items that are reclassified from accumulated other comprehensive income to net
income separately with their respective components of net income and other comprehensive net income. Entities
should continue to report reclassifications out of accumulated other comprehensive income using guidance in
effect before ASU 2011-05 was issued. ASU 2011-05 will be effective for the Company in its first quarter of
fiscal 2013, though earlier adoption is permitted. The update will be applied retrospectively upon adoption, and
the Company believes the adoption will not have a material effect on its 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, 2012
and 2011, the Company had deposits with domestic 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 invests funds overnight
under a repurchase agreement with its bank which is collateralized by securities of the United States Federal
agencies. The Company generally invests primarily in short-term U.S. Treasury Securities. The Company
believes its investments are of high credit quality.

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, 2012, sales to the Company’s largest client represented 21% of both its revenues and
revenues net of third-party charges as compared to 27% and 18%, respectively, at September 30, 2011. The
remaining balance of the Company’s fiscal 2012 revenues was derived from varied clients and none represented
10% or more of its fiscal 2012 revenues.

17. Subsequent Events

The Company evaluates subsequent events through the date the financial statements are issued in
conformity with generally accepted accounting principles. The Company considers its financial statements issued
when they are widely distributed to users, such as filing with the SEC.

F-20

DAWSON GEOPHYSICAL COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

18. Quarterly Consolidated Financial Data (Unaudited)

Fiscal 2011:

Operating revenues . . . . . . . . . . . . .
(Loss) income from operations . . . .
Net (loss) income . . . . . . . . . . . . . .
Basic (loss) income per common

share . . . . . . . . . . . . . . . . . . . . . .

Diluted (loss) income per common

share . . . . . . . . . . . . . . . . . . . . . .

Fiscal 2012:

Operating revenues . . . . . . . . . . . . .
Income from operations . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . .
Basic income per common share . . .
Diluted income per common

December 31

March 31

June 30

September 30

Quarter Ended

$72,653,000
$ (2,817,000)
$ (1,667,000)

$78,337,000
$ (6,545,000)
$ (4,857,000)

$98,033,000
898,000
$
334,000
$

$84,256,000
$ 5,138,000
$ 2,944,000

(0.21)

(0.62)

0.04

0.38

0.37

$92,382,000
$ 3,226,000
$ 3,231,000
0.41
$

$85,546,000
$ 9,446,000
$ 5,589,000
0.71
$

$68,348,000
$ 1,798,000
$ 1,141,000
0.15
$

$72,998,000
$ 2,131,000
$ 1,152,000
0.15
$

share . . . . . . . . . . . . . . . . . . . . . .

0.41

0.70

0.14

0.15

Basic income per share and diluted income per share are computed independently for each of the quarters
presented. Therefore, the sum of quarterly basic and diluted per share information may not equal the annual basic
and diluted earnings per share.

F-21

Schedule II

Dawson Geophysical Company

Consolidated Valuation and Qualifying Accounts

Balance at
Beginning
of Period

Charged to
Costs and
Expenses

Deductions

Balance at
End of
Period

Allowance for doubtful accounts*:
Fiscal Year:

2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$155,000
639,000
533,000

$327,000
231,000
256,000

$232,000
715,000
150,000

$250,000
155,000
639,000

Valuation allowance for deferred tax assets:
Fiscal Year:

— $

19,000
58,000

(19,000)
(39,000)

— $
—
—

—
—
19,000

* Deductions related to allowance for doubtful accounts represent amounts that have been deemed uncollectible

and written off by the Company.

F-22

Number

3.1

3.2

3.3

3.4

3.5

4.1

10.1†

10.2†

10.3†

10.4†

10.5†

10.6†

10.7†

10.8†

10.9†

INDEX TO EXHIBITS

Exhibit

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 for the first quarter ended
December 31, 2006 (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).

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 for the fiscal year ended September 30,
2010 (File No. 001-34404) and incorporated herein by reference).

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).

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).

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).

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).

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).

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).

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).

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).

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).

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).

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).

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).

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).

Number

Exhibit

10.10*

Form of Master Geophysical Data Acquisition Agreement.

10.11*

Form of Supplemental Agreement to Master Geophysical Data Acquisition Agreement.

10.12†

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).

10.13

10.14

10.15

10.16

21.1*

23.1*

31.1*

31.2*

32.1*

32.2*

**101

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).

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).

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).

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).

List of Subsidiaries.

Consent of Independent Registered Public Accounting Firm.

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

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

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.”

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.”

formatted

30, 2012,

The following materials from the Company’s Annual Report on Form 10-K for the year ended
September
in XBRL (Extensible Business Reporting Language):
(i) Consolidated Balance Sheets at September 30, 2012 and September 30, 2011, (ii) Consolidated
Statements of Operations for the years ended September 30, 2012, 2011 and 2010, (iii) Consolidated
Statements of Stockholders’ Equity and Other Comprehensive Income (Loss) for the years ended
September 30, 2012, 2011 and 2010, (iv) Consolidated Statements of Cash Flows for the years ended
September 30, 2012, 2011 and 2010, and (v) Notes to Consolidated Financial Statements.

* Filed herewith.

**Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a
registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or
Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these
sections.

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

This page intentionally left blank

C o r p o r a t e O f f i c e s

D i r e c t o r s

O f f i c e r s

508 West Wall, Suite 800
Midland, Texas 79701-5010

Phone: 432-684-3000
432-684-3030
Fax:
info@dawson3d.com
Email:

Annual Meeting
The Annual Meeting of Shareholders will
be held January 22, 2013, at 10:00 a.m.
at The Petroleum Club of Midland,
501 West Wall, Midland, Texas 79701

Registrar and Transfer Agent
Computershare Shareowner Services LLC
Jersey City, New Jersey

Stock Exchange Listing
Nasdaq Global MarketSM
Symbol: DWSN

Independent Public Accountants
KPMG LLP
Dallas, Texas

L. Decker Dawson
Chairman of the Board

Stephen C. Jumper
President and
Chief Executive Officer

C. Ray Tobias
Executive Vice President
and Chief Operating Officer

Christina W. Hagan
Executive Vice President,
Secretary and Chief Financial Officer

James W. Thomas
Executive Vice President
and Chief Technology Officer

K.S. Forsdick
Senior Vice President

Melody Y. Crowl
Treasurer

Paul H. Brown
Sugar Land, Texas
Management Consultant

Craig W. Cooper
Cypress, Texas
Retired Geophysicist

L. Decker Dawson
Midland, Texas
Chairman of the Board
of the Company

Gary M. Hoover, Ph.D.
Bartlesville, Oklahoma
Retired Geophysicist

Stephen C. Jumper
Midland, Texas
President and Chief Executive Officer
of the Company

Jack D. Ladd
Midland, Texas
Dean and Professor of Management
in The School of Business at UTPB

Ted R. North
Edmond, Oklahoma
Certified Public Accountant

Tim C. Thompson
Midland, Texas
Management Consultant

Forms 10-Q and 10-K reports will be available on the
internet at www.sec.gov each quarter, and additional
information will be available at www.dawson3d.com.

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N A S D A Q L i s t e d : D W S N w w w. d a w s o n 3 d . c o m