U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-KSB

(Mark One)

ý                                 ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

o                                 TRANSITION REPORT UNDER SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the period from         to        

Commission File Number 0-14908

TGC INDUSTRIES, INC.

(Name of small business issuer in its charter)

Securities registered under Section 12(b) of the Exchange Act:  NONE

Securities registered under Section 12(g) of the Exchange Act:

Common Stock ($.01 Par Value)

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes  o   No  ý

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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  ý   No  o

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will 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-KSB or any amendment to this Form 10-KSB. ý

Indicate by check mark whether the registrant is a shell company as defined by Rule 12b-2 of the Exchange Act. Yes  o   No  ý

State issuer’s revenues (from continuing operations) for its most recent fiscal year:  $30,851,963

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of March 20, 2006 (for the purpose of this calculation only directors, executive officers, and 10% or greater stockholders are deemed to be affiliates):  $92,672,939

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date.

Transitional Small Business Disclosure Format (check one). Yes  o   No  ý

Part I

ITEM 1. DESCRIPTION OF BUSINESS.

TGC Industries, Inc. (“TGC” or the “Company”) is a Texas corporation engaged in the geophysical service business, primarily conducting Three-D (“3-D”) surveys for clients in the oil and gas business. TGC’s principal business office is located at 1304 Summit Avenue, Suite 2, Plano, Texas 75074. (Telephone: 972-881-1099).

BUSINESS

History

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

We are a leading provider of seismic data acquisition services throughout the continental U.S. As of December 31, 2005, we operated five seismic crews, and we deployed our sixth seismic crew in January of 2006. These seismic crews supply seismic data to companies engaged in the domestic exploration and development of oil and natural gas on land and in land-to-water transition areas. Our customers rely on seismic data to identify areas where subsurface conditions are favorable for the accumulation of existing hydrocarbons, to optimize the development and production of hydrocarbon reservoirs, to better delineate existing oil and natural gas fields, and to augment reservoir management techniques.

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

The Industry

Technological advances in seismic equipment and computing allow the seismic industry to economically acquire and process immense volumes of seismic data which produce more precise images of the earth’s subsurface. The latest accepted method of seismic data acquisition, processing, and the subsequent interpretation of the processed data is the 3-D seismic method. Geophysicists use computer workstations to interpret 3-D data volumes, identify subsurface anomalies, and generate a geologic model of subsurface features.

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

Currently, the seismic data acquisition industry is made up of a number of companies divided into two groups. The first group is made up of five publicly-traded companies with long operating histories who field numerous crews and work in a number of different regions and terrain. This group includes us, Dawson Geophysical Company, Geo Kinetics, Inc., Veritas DGC, Inc., and Petroleum Geo Services. These companies field approximately 50% of the estimated 55 seismic crews currently operating in the continental U.S. The second group is made up of smaller companies who generally run one or two seismic crews and often specialize in specific regions or type of operation.

We provide our seismic data acquisition services primarily to domestic onshore oil and natural gas exploration and development companies for use in the onshore drilling and production of oil and natural gas in the continental U.S. The main factors influencing demand for seismic data acquisition services in our industry are the level of drilling activity by oil and natural gas companies and the sizes of such companies’ exploration and development budgets, which, in turn, depend largely on current and anticipated future crude oil and natural gas prices and depletion rates. Current market indicators suggest an increasing demand for oil and natural gas coupled with a flat or declining production curve, which we believe may result in the continuation of historically high oil and natural gas commodity prices. From 2003 through 2025, consumption of oil and natural gas in the U.S. are each projected to grow at an annual rate of 1.5%. However, U.S. domestic production of oil is projected to decrease (0.8)% annually, and natural gas is projected to grow at an annual rate of 0.6% over the same period. Additionally, the Energy Information Administration (“EIA”) recently estimated that by 2010 U.S. domestic consumption of oil and natural gas will outpace domestic production by 139.1% and 24.2%, respectively. By

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2025, EIA forecasts that these supply and demand gaps for oil and natural gas may expand to 216.3% and 40.0%, respectively. The majority of the wells drilled by our customers have been wells drilled in search of natural gas reserves.

Increased decline rates in natural gas basins in the U.S. have also led to an increase in the price of oil and natural gas. Over the past 10 years, the number of U.S. natural gas wells drilled has increased significantly; however, a corresponding increase in production has not been realized. We believe that a significant reason for the limited supply response, even as drilling activities have increased, is an acceleration in the decline rates of production from new natural gas wells drilled. A study published by the National Petroleum Council in September 2003 concluded, from analysis of production data over the preceding 10 years, that as a result of domestic natural gas decline rates of 25% to 30% per year, 80% of natural gas production in 10 years will be from wells that have not yet been developed. We believe that this tends to support a sustained higher natural gas price environment, which should create incentives for exploration and development companies to increase seismic activities in the U.S. As a result of improvements in extraction technologies coupled with general increases in prices, oil and natural gas companies increasingly are exploring for and developing “unconventional” resources, including hydrocarbons from tight sands and shales in new areas.

We anticipate that oil and natural gas exploration and development companies will continue to respond to sustained increases in demand and corresponding higher future oil and natural gas commodity prices by expanding their exploration and drilling activities through increased capital spending. According to RigData, weekly average onshore well permits issued in 2005 and 2004 were 1,349 and 1,122, respectively, an increase of 20.2%. Based upon Baker-Hughes rig count data, the 2005 and 2004 domestic onshore rig count averaged 1,666 and 1,392 rigs, respectively, an increase of 19.7%. Based on strong oil and natural gas prices and increasing exploration and development budgets of oil and natural gas companies, we anticipate continued growth in the industry.

In addition, since January 1, 2006, new energy legislation permits the tax deduction of seismic data acquisition services over a 24 month period instead of the longer write-off period previously in effect. We believe that this accelerated tax write-off may encourage additional exploration and development activity.

We anticipate that oil and natural gas exploration and development companies will continue to respond to sustained increases in demand by expanding their exploration and drilling activities and increasing capital spending. We believe that a continued increase in U.S. seismic work will be required for the oil and natural gas industry to help meet the expected increased demand for oil and natural gas in the U.S.

Equipment and Crews

In 2002, we downsized from two crews to one crew because of a reduced demand for our services. As a result, we began exploring ways of increasing bidding opportunities in existing markets. In February of 2002, we entered into an agreement to trade in our shot hole drilling equipment for five buggy-mounted vibroseis units. The purchase of these units has opened up a new market opportunity for us, thereby increasing our bidding opportunities. We have been successful in the vibroseis market with a significant portion of our 2005, 2004, and 2003 revenues being generated from vibroseis contracts. We announced in January of 2004 that, in view of the fact that oil and natural gas exploration and development companies had increased the levels of activity in their domestic oil and natural gas exploration programs, we had acquired three new vibroseis units and deployed a second seismic data acquisition crew. In June of 2004, in response to the continued increased level of activity in the domestic oil and natural gas market, we deployed our third seismic data acquisition crew. In the fourth quarter of 2004, we acquired, and placed into service, our first new ARAM ARIES recording system. In July of 2005, we deployed our fourth seismic data acquisition crew along with our second new ARAM ARIES recording system. In November of 2005, we deployed our fifth seismic data acquisition crew along with our third new ARAM ARIES recording system. In December of 2005, we completed a loan transaction with a commercial lender for the purpose of providing funds for the purchase of our fourth new ARAM ARIES recording system. In January of 2006, we deployed a sixth crew to operate this fourth new ARAM ARIES recording system.

Two of our crews utilize the Opseis Eagle data gathering system. This system employs radio-frequency (“RF”) telemetry technology providing seismic data-gathering services to land-to-water transition areas, rivers, lakes, inaccessible terrain, deserts, and man-made barriers such as highways and cities. RF telemetry transmits data in “real time” via remote units set up on a shot line. These lightweight units, called Seismic Acquisition Remove (“SAR”) units, can be set up and repositioned quickly and easily without cumbersome cables. Multiple SAR units represent the first surface mount technology and the ability to gather data from any terrain through any obstacle. Our crews have great flexibility in energy sources and placement of SAR units in the field.

In October of 2004, June of 2005, November of 2005, and December of 2005 we purchased new state-of-the-art ARAM ARIES recording systems. These systems employ cable telemetry technology enhanced by multiple baseline and redundant cable connections that provide seismic data acquisition services with increased reliability. This allows our crews to record data faster, thereby increasing their productivity and freeing up equipment for use by our other crews. Subsurface requirements dictate the number of channels necessary to perform our services, and the increased number of recording channels we obtained with these new recording systems give us greater operational flexibility. Each new ARAM ARIES recording system comes with a 24 month warranty and system upgrades.

We currently own equipment for six land-based seismic data acquisition crews and 27 vibration vehicles equipped with Pelton electronics. Each crew consists of approximately 35 to 45 technicians with associated vehicles, geophones, a seismic recording system, energy sources, cables, and a variety of other equipment. Each crew has one central recording vehicle which captures seismic data. This data is recorded on a CD ROM or data tape which is delivered to a data processing center selected by the customer.

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Additionally, we currently plan to purchase peripheral seismic equipment, including seven additional vibration vehicles, with a portion of the proceeds from our public offering which was completed in October of 2005.

Capital Expenditures

We believe that it is essential to take advantage of advances in seismic technology and to commit capital to purchase and update our equipment cost effectively. Purchasing and updating seismic equipment and technology involves a continuing commitment to capital spending. For fiscal year 2005, capital expenditures were approximately $20,525,000 compared with approximately $5,795,000 for 2004.

Customers and Consultants

Our customers are major and independent oil and natural gas exploration and development companies. The services we provide to our customers vary according to the size and needs of each customer. Our services are marketed by supervisory and executive personnel who contact customers to determine their needs and respond to customer inquiries regarding the availability of crews. Contacts are based principally upon professional relationships developed over a number of years. There are a number of consultants in the oil and natural gas industry who process and interpret seismic data for oil and natural gas companies. These consultants can have an influence in determining which company their customers use to acquire seismic data.

One of the benefits from the rapid growth we experienced in 2005 is the fact that we have been able to reduce our customer concentration. For the year ended December 31, 2005, two customers accounted for approximately 11.6% and 10.6% of our revenues. For the year ended December 31, 2004, two customers accounted for approximately 33.6% and 14.8% of our revenues. We expect that this reduction in customer concentration will continue during 2006.

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

Contracts

Our contracts are obtained either through competitive bidding or as a result of customer negotiations. Our services are conducted under general service agreements for seismic data acquisition services which define certain obligations for us and for our customers. A supplemental agreement setting forth the terms of a specific project, which may be cancelled by either party upon 60 days advance written notice, is entered into for every project. We currently operate under supplemental agreements that are either “turnkey” agreements providing for a fixed fee to be paid to us for each unit of data acquired or “term” agreements providing for a fixed hourly, daily, or monthly fee during the term of the project or projects. Turnkey agreements generally provide us with more profit potential, but involve more risks because of the potential of crew downtime or operational delays. 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 attempt to negotiate on a project-by-project basis some level of weather downtime protection within our agreements; however, we may still experience some risk due to inclement weather. We strive to manage our crews and equipment as a portfolio, balancing the mix of turnkey and term contracts and the type of equipment.

The energy source for each contract is determined by the surface terrain and the sub-surface requirements. Although our contracts involving dynamite make up a small percentage of the total number of contracts, since January of 2003 they have represented approximately 28% of our total revenues. The range of revenues is influenced by the number of dynamite projects we conduct in a given year. We incur higher costs on our dynamite projects that we pass on to our customers and, as a result, we recognize both higher revenues and higher costs of services, thereby reducing our margin.

Sub-Contractors and Equipment Rental

We engage a number of sub-contractors to perform specialized services related to the use of dynamite that is required on some projects. These sub-contractors provide services that include supplying dynamite, drilling holes in connection with the use of dynamite and specialized surveying crews that can clear heavy brush and trees in order to complete the survey. Since there are a number of contractors that provide these types of services, we are not dependent on any single contractor or group of contractors for the successful completion of our projects.

We also rent certain specialized equipment on a project-by-project basis, such as boats and specialized geophones.

Competition

The acquisition of seismic data for the oil and natural gas industry is a highly competitive business. There are approximately 55 seismic crews currently operating in the continental United States. Contracts for such services generally are awarded on the basis of price quotations, crew experience, and the availability of crews to perform in a timely manner, although factors other than price, such as crew safety performance history, 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 Dawson Geophysical Company, Geo Kinetics, Inc., Petroleum Geo Services, and to a lesser extent, Veritas DGC, Inc. In addition to the previously named companies, we also compete for projects from time to time with smaller seismic companies which operate in local markets with only one or two crews. We believe that our long-term industry expertise, the

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customer relationships developed over our history, and our financial stability give us an advantage over most of our competitors in the industry.

Employees

As of December 31, 2005, we employed a total of 152 full-time (non-union) employees, of which 9 consisted of management, sales and administrative personnel with the remainder being crew personnel. We also hire contract labor for our crews on an as-needed basis. We believe our relationship with our employees to be satisfactory.

Data Bank

We own a data bank which contains gravity data, and to a lesser extent magnetic data, from many of the major oil and natural gas producing areas located within the U.S. We do not have a seismic data bank. Our data bank information has been amassed through participatory surveys as well as speculative surveys historically funded by us alone. All data and interpretations may be licensed to customers at a fraction of the cost of newly acquired data. However, the licensing of this data is not a significant portion of our revenues.

Operating Risks and Insurance

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

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

We do not carry insurance against certain risks that we could experience, such as business interruption resulting from equipment maintenance or weather delays. We obtain insurance against certain property and personal casualty risks and other risks when such insurance is available and when our management considers it advisable to do so. Currently, our insurance coverage consists of employers liability with limits of $1,000,000 per accident and $2,000,000 in the aggregate, commercial general liability of $1,000,000 per accident and $2,000,000 in the aggregate, pollution liability of $1,000,000 per accident and $2,000,000 in the aggregate, automobile liability with a $1,000,000 combined single limit, and a $10,000,000 umbrella policy. Our general service agreements require us to have specific amounts of insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us.

ITEM 2. DESCRIPTION OF PROPERTY.

Our headquarters are in leased facilities located in Plano, Texas, from which we conduct all of our current operations. These facilities include approximately 10,500 square feet of office and warehouse space and an outdoor storage area of approximately 20,000 square feet. The monthly rent is $6,559. This facility is used to house our corporate offices and serves as the headquarters for our seismic data acquisition services business. In September of 2005, we added an additional 10,000 square feet of office and warehouse space and an additional 10,000 square feet of outdoor storage to accommodate our recent growth. This facility is used primarily to repair geophysical equipment. The monthly rent is $3,542. In January of 2006, we leased a 600 square foot facility in Houston, Texas, to be used as a sales office. The monthly rent is $734. The Company is not responsible for insuring these facilities. The conditions of these facilities are good, and we believe that these properties are suitable and adequate for our foreseeable needs.

ITEM 3. LEGAL PROCEEDINGS.

On December 28, 2004, one of our employees was killed in a work-related accident. On July 11, 2005, the deceased employee’s widow filed suit against us in a state court in Harris County, Texas, seeking monetary damages. Our insurance company is currently providing legal counsel to represent us in this case, and we do not believe that the case’s disposition will have a material adverse affect on our financial condition.

We are a defendant in various other legal actions that arise out of the normal course of business. In our opinion, none of these actions will result in any significant loss to us.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

No matters were submitted by the Company, during the fourth quarter of the fiscal year ended December 31, 2005, to a vote of our security holders through the solicitation of proxies or otherwise.

Part II

ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS.

Market Prices

From May 25, 2002, through April 15, 2005, our common stock was traded over-the-counter on the National Association of Securities Dealers, Inc. Over-The-Counter Bulletin Board System (using the trading symbol “TGCI”). Because of our improved financial condition which has led to a substantial increase in our stock price and the market value of our publicly-held shares, we qualified for, and began trading on, the American Stock Exchange (“AMEX”) on April 18, 2005, under our current trading symbol “TGE.”

In the following table, the prices shown through April 15, 2005, represent prices among the dealers on the Over-The-Counter Bulletin Board System and do not include retail mark-ups, mark-downs, or commissions, and do not necessarily represent actual transactions. Beginning on April 18, 2005, the following table shows the high and low sales prices reported for our common stock on the AMEX.

The number of shareholders of record of TGE’s Common Stock as of March 20, 2006, was 139. Due to the number of shares held in nominee or street name, we believe that there are a significantly greater number of beneficial owners of our common stock. As of such date, CEDE & CO. held 11,040,403 shares in street name. On March 20, 2006, our common stock was quoted at a closing sales price of $9.36.

While there are currently no restrictions prohibiting us from paying cash dividends to our shareholders, we have not paid any cash dividends on our common stock in the past, and we do not anticipate paying any dividends in the foreseeable future. Payment of any cash dividends in the future, however, is in the discretion of our board of directors and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by our board of directors. Earnings, if any, are expected to be retained to fund our future operations.

ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OF PLAN OF OPERATIONS.

The following discussion and analysis should be read in conjunction with our financial statements and related notes thereto included elsewhere in this Form 10-KSB. Portions of this document that are not statements of historical or current fact are forward-looking statements that involve risk and uncertainties, such as statements of our plans, objectives, expectations, and intentions. The cautionary statements made in this Form 10-KSB should be read as applying to all related forward-looking statements wherever they appear in this Form 10-KSB. Our actual results could differ materially from those anticipated in the forward-looking statements. Factors that could cause our actual results to differ materially from those anticipated include those discussed in “Risk Factors,” “Business,” and “Forward-Looking Statements.”

Overview

We are one of the leading providers of seismic data acquisition services in the continental U.S. As of December 31, 2005, we operated five seismic crews, and we deployed our sixth seismic crew in January of 2006. Substantially all of our revenues are derived from the seismic data acquisition services which we provide to our customers, primarily major and independent oil and natural gas exploration and development companies in the continental U.S. Demand for our services depends upon the level of spending by these oil and natural gas companies for exploration, production, and development, which activities depend, in part, on oil and natural gas prices. 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 continue to have a significant impact on our business and results of operations.

Our return to profitability in 2003 after several years of losses is directly related to an increase in the level of exploration and development for domestic oil and natural gas. The increased level of exploration and development is a function of higher prices for oil

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and natural gas. As a result of the increase in domestic exploration spending, we have experienced an increased demand for our seismic data acquisition services.

We continue to focus on increasing revenues and profitability. Due to the fixed costs we incur, consisting primarily of depreciation, a non-cash item, and maintenance expenses associated with seismic data acquisition equipment and crew costs, we strive to maintain high utilization rates for our crews. While our revenues are mainly affected by the level of customer demand for our services, our revenues are also affected by the pricing for our services that we negotiate with our customers. As a result of the fixed cost structure of our business, our profitability is affected by the level of productivity of our seismic data acquisition crews including crew downtime related to inclement weather, unplanned equipment repairs, and delays in acquiring land access permits. Consequently, our continued growth in revenues and improved profitability is due, in part, to our successful efforts to negotiate more favorable weather protection provisions in our service agreements with our customers, our ability to mitigate access permit delays and our continued efforts to improve overall crew productivity by purchasing equipment that operates more efficiently in our markets. Although our customers may cancel their supplemental service agreements with us on short notice, we believe that we currently have sufficient contracts to sustain operations through the first half of 2006.

How We Generate Our Revenues

Our contracts are obtained either through competitive bidding or as a result of negotiations with customers. Contract terms offered by us are generally dependent on the complexity and risk of operations, energy source technique being used (vibroseis or dynamite), type of equipment, and the anticipated duration of the work to be performed. The majority of our contracts are typically subject to termination by the customer upon 60 days advance written notice to us with little or no penalty.

How We Manage Our Operations

Our management team uses a variety of tools to manage our operations. These tools include monitoring our: (1) seismic crew performance; (2) project scheduling calendar; (3) schedule of pending proposals; and (4) safety performance.

Seismic crew performance.  We monitor crew performance on a daily basis by monitoring the production obtained by each crew on the previous day in relation to the type of geography, weather, and type of acquisition technique being employed — vibroseis or dynamite. This review allows us to monitor the profitability of turnkey contracts and reallocate resources if necessary to increase productivity. We expect our cost of services and selling, general and administrative (“SG&A”) expenses to increase as a percentage of sales during periods in which we deploy additional crews, but decrease as a percentage of sales as new crews become more efficient and higher revenues are generated.

Project scheduling calendar.  Our management team reviews our project scheduling calendar on a daily basis. Monitoring this schedule allows management to schedule or reschedule projects to most efficiently utilize our resources. This continuous monitoring allows us to limit our crews’ downtime between jobs and helps us communicate effectively with customers concerning the estimated start dates and completion dates of pending projects.

Schedule of pending proposals.  We monitor on a daily basis our list of outstanding proposals. By monitoring this list, we are able to more effectively schedule our future projects and determine whether we need to follow up with the customer on any of the pending proposals.

Safety performance.  Maintaining a strong safety record is a critical component of our operational success. Our field level management team holds a safety meeting every day to discuss any safety issues that arose during the previous day. In an effort to maintain our historic levels of safety performance, we have engaged a safety specialist through our insurance agency to conduct our safety training courses and to review our safety reports on a regular basis.

Our Growth Strategies

We believe that there are significant opportunities for us to increase our revenues and market position in the continental U.S. onshore seismic market by:

•       optimizing equipment and crew utilization;

•       maintaining our state-of-the-art technology position;

•       maintaining our efficient management structure;

•       managing the mix and terms of our contracts; and

•       maintaining a conservative balance sheet and disciplined capital spending program.

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Results of Operations

Year Ended December 31, 2005, Compared to Year Ended December 31, 2004

Revenues. Our revenues were $30,851,963 for the year ended December 31, 2005, compared to $20,084,175 for the same period of 2004, an increase of 53.6%. This increase in revenues was attributable to several factors including increasing the number of seismic data acquisition crews operating in 2005 compared with the number of crews operating in 2004, increased demand for our services due to increased exploration and development activity by domestic oil and natural gas companies, price improvements and more favorable contract terms in our agreements with customers, and the increased productivity derived from our new ARAM ARIES recording systems. In January of 2004, we deployed our second seismic data acquisition crew. In June of 2004, we deployed our third seismic data acquisition crew. In the fourth quarter of 2004, we placed our first ARAM ARIES recording system into service. In July of 2005, we deployed our fourth seismic data acquisition crew along with our second new ARAM ARIES recording system, and in November of 2005, we deployed our fifth seismic data acquisition crew along with our third ARAM ARIES recording system.

Cost of services. Cost of services includes the wages and expenses directly related to our field crews and support operations, as well as third party costs associated with certain contracts provided by non-employee contractors, but excludes depreciation and amortization expense. Our cost of services was $18,152,118 for the year ended December 31, 2005, compared to $14,707,648 for the same period of 2004, an increase of 23.4%. This increase was principally attributable to our increase in revenues. However, as a percentage of revenues, cost of services was 58.8% for the year ended December 31, 2005, compared to 73.2% for the same period of 2004, a decrease of 14.4%. This decrease was primarily attributable to the mix of contracts, non-recurring equipment rental expense that occurred in the second quarter of 2004, and the increased productivity attributable to the new ARAM ARIES recording systems.

Selling, general, and administrative. SG&A expenses include the wages and salaries of administrative and sales personnel, as well as other general overhead costs not directly related to field operations. SG&A expenses were $2,149,350 for the year ended December 31, 2005, compared to $1,277,161 for the same period of 2004, an increase of 68.3%. This increase was primarily attributable to additional compensation expense for incentive bonuses, additional expenses associated with the Company’s common stock being listed on the American Stock Exchange, increased insurance costs, increased legal expense, and expenses associated with additional personnel in 2005 compared with 2004. SG&A expenses as a percent of revenue increased to 7.0% for the year ended December 31, 2005, from 6.4% for the same period of 2004.

Depreciation and amortization expense. Depreciation and amortization expense was $3,201,236 for the year ended December 31, 2005, compared to $1,106,022 for the same period of 2004, an increase of 189.4%. This increase was attributable to capital expenditures of $5,794,553 in 2004, which was incurred predominantly in the fourth quarter, and to that portion of the $20,525,672 in capital expenditures during 2005 that were placed into service during that year. As a result, depreciation and amortization expense as a percent of revenue increased to 10.4% for the year ended December 31, 2005, from 5.5% for the same period of 2004.

Income from operations. Income from operations was $7,349,259 for the year ended December 31, 2005, compared to $2,993,344 for the same period of 2004, an increase of 145.5%. This increase was primarily attributable to the increase in revenues and the improvement in our cost of services, partially offset by increases in SG&A and depreciation and amortization expenses. EBITDA increased $6,451,129 to $10,550,495 for the year ended December 31, 2005, from $4,099,366 in the same period of 2004, an increase of 157.4%. This increase was a result of those factors mentioned above. For a definition of EBITDA, a reconciliation of EBITDA to net income, and a discussion of EBITDA, see the section entitled “Non-GAAP Financial Measure” which follows.

Interest expense. Interest expense was $364,848 for the year ended December 31, 2005, compared to $60,878 for the same period of 2004. This increase was primarily attributable to the debt incurred for the purchase of our first two ARAM ARIES seismic recording systems and the debt associated with vehicles leased under capital leases.

Income tax expense. Income tax expense was $783,633 for the year ended December 31, 2005, compared to $64,127 for the same period of 2004. As of December 31, 2004, we had net operating loss carryforwards of approximately $4,980,000 available to offset future taxable income. These net operating loss carryforwards were depleted during 2005. As a result, the Company had an effective tax rate of 11.2% in 2005, but will incur federal (and various state income) taxes in 2006 at regular statutory rates.

Non-GAAP Financial Measure

We define EBITDA as net income plus expenses of interest, income taxes, depreciation, and amortization. We use 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 and in relation to other companies that own similar assets and that we believe calculate EBITDA in a manner similar to us; and

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

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We also understand that such data is used by investors to assess our performance. However, EBITDA is not a measure of operating income, operating performance, or liquidity presented in accordance with General Accepted Accounting Principals (GAAP). When assessing our operating performance or our liquidity, you should not consider this data in isolation or as a substitute for our net income, cash flow from operating activities, or other cash flow data calculated in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, EBITDA as presented below may not be comparable to similarly titled measures of other companies. Further, the results presented by EBITDA cannot be achieved without incurring the costs that the measure excludes: interest, taxes, depreciation, and amortization.

The following table reconciles our EBITDA to our net income:

Liquidity and Capital Resources

Liquidity

Cash flows from operating activities.

Net cash provided by operating activities was $5,739,614 for the year ended December 31, 2005, compared to $4,165,754 for the same period of 2004. The $1,573,860 increase was principally due to a $3,332,439 increase in net income and a $2,095,214 increase in depreciation and amortization expense offset by an increase in the accounts receivable of $1,947,130 and an increase in costs and estimated earnings in excess of billings on uncompleted contracts of $3,253,330. Significant components of net cash provided by operations are the changes, period over period, in accounts receivable, costs, and estimated earnings in excess of billings on uncompleted contracts, accounts payable, and billings in excess of costs and estimated earnings on uncompleted contracts. Accounts receivable increased $857,630 during the year ended December 31, 2004, to $1,655,084 and increased $2,804,760 during the year ended December 31, 2005, to $4,459,844. These receivable fluctuations were primarily due to the timing of billings and collections. Costs and estimated earnings in excess of billings on uncompleted contracts increased $201,030 during the year ended December 31, 2004, to $231,524 and increased $3,454,360 during the year ended December 31, 2005, to $3,685,884. These costs and estimated earnings in excess of billings on uncompleted contracts fluctuations were primarily due to the increased level of activity. Accounts payable increased $621,633 during the year ended December 31, 2004, to $741,782 and increased $1,222,884 during the year ended December 31, 2005, to $1,964,666. These payable fluctuations were primarily due to the mix of contracts and the timing of receipt and payment of invoices. Billings in excess of costs and estimated earnings on uncompleted contracts increased $361,977 during the year ended December 31, 2004, to $657,956 and increased $762,728 during the year ended December 31, 2005, to $1,420,684. These billings in excess of costs and estimated earnings on uncompleted contracts fluctuations were primarily due to the timing of billings and revenue recognition.

Working capital increased $ 9,099,016 to $9,952,149 as of December 31, 2005, from the December 31, 2004, working capital of $853,133. This increase was due primarily to an increase in cash and cash equivalents of $7,669,505, an increase in trade accounts receivable of $2,804,760, and an increase in costs and estimated earnings in excess of billings on uncompleted contracts of $3,454,360 offset by increases in trade accounts payable of $1,222,884, billings in excess of costs and estimated earnings on uncompleted contracts of $762,728, and current maturities of notes payable of $2,685,290. These changes were primarily the result of net proceeds the Company received from its public offering completed in October of 2005, the increased level of activity in 2005, and the increased debt levels associated with the financing of two additional ARAM ARIES seismic recording systems and three vibration vehicles in 2005.

Cash flows used in investing activities.

Net cash used in investing activities was $2,636,741 for the year ended December 31, 2004, and $11,358,108 for the year ended December 31, 2005. The $8,721,367 increase was due to an increase in capital expenditures of $8,853,795 offset by an increase in proceeds from sale of property and equipment of $132,428.

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Cash flows provided by (used in) financing activities.

Net cash used in financing activities was $724,330 for the year ended December 31, 2004. Net cash provided by financing activities was $13,287,999 for the year ended December 31, 2005. The change was due primarily to net proceeds from the issuance of common stock of $40,002,839, proceeds from issuance of debt of $430,581, and an increase in proceeds from exercise of stock options of $76,239 offset by redemption of stock purchase warrants of $24,001,298, an increase in principal payments on notes payable of $2,094,291, and an increase in principal payments on capital lease obligations of $421,550.

Capital expenditures.

During the year ended December 31, 2005, capital expenditures of $11,491,786 were used to acquire additional seismic equipment and vehicles. In June of 2005, we completed a $3,366,253 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our second new ARAM ARIES recording system. This loan is repayable over a period of thirty-six months at a fixed per annum interest rate of 7.25%. The loan is collateralized by the new recording system equipment and the recording truck and two semi-trailers that transport the newly purchased equipment between projects. During the third quarter of 2005, we completed a $ 858,705 loan transaction with a commercial lender for the purpose of providing funds for the purchase of three new buggy mounted vibration vehicles. This loan is repayable over a period of thirty-six months at a fixed per annum interest rate of 7.25%. This loan is collateralized by the three new buggy mounted vibration vehicles. In September of 2005 we entered into an equipment sales contract to purchase nine new vibration vehicles at a cost of approximately $ 2,936,000. We took delivery of these vibration vehicles during the first quarter of 2006, and proceeds from our public offering were used to purchase these vibration vehicles. In November of 2005, we purchased our third new ARAM ARIES recording system using $4,088,127 of the proceeds from the public offering. In addition, in December of 2005, we completed a $3,791,338 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our fourth new ARAM ARIES recording system. This loan is repayable over a period of thirty-six months at a fixed per annum interest rate of 7.78%. This loan is collateralized by the new recording system equipment and the recording truck and two semi-trailers that transport the newly purchased equipment between projects. In January of 2006, we entered into an equipment sales contract to purchase seven new buggy mounted vibration vehicles at a cost of approximately $2,325,000. We anticipate delivery of these units during the third quarter of 2006. Proceeds from the public offering will be used to purchase these buggy mounted vibration vehicles. Although we do not budget for our capital expenditures, we may purchase additional equipment as the demand for our services increases.

Capital Resources

Historically, we have relied on cash generated from operations and short-term borrowings from commercial banks and equipment lenders and loans from directors to fund our working capital requirements and capital expenditures.

During a period beginning in 1999 and ending in 2003, we did not have adequate financial strength to enable us to obtain from independent sources financing needed to enable us to sustain our operations. With no other financial sources available, on several different occasions during this period of time certain of our directors both made direct loans to us and agreed to provide us with needed lines of credit. In connection with these loans and lines of credit, we issued stock purchase warrants. When we completed in October of 2005 a public offering of our common stock, we used a portion of the proceeds received to purchase from these directors all of their stock purchase warrants which they had acquired for providing such financial accommodations. Financial advisors to the Company had suggested that this would simplify the Company’s capitalization thereby allowing investors to better understand the Company’s earnings per share calculations. The purchase price of each of these warrants was equal to the public offering price of the Company’s common stock less the total of the exercise price of each warrant and each warrant’s proportionate share of the underwriting discounts and commissions (such proportionate share being based on the “in the money” value of each warrant).

In October of 2004, we completed a $2,386,649 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our first new ARAM ARIES recording system. The loan is repayable over a period of 36 months at a fixed per annum interest rate of 6.85%. The loan is collateralized by the new recording system equipment and the recording vehicle and two semi-trailers that transport the equipment between projects.

In April of 2005, we entered into a revolving line of credit loan agreement with a commercial bank. On September 16, 2005, we amended our revolving line of credit under which we may borrow, repay, and re-borrow, from time to time until September 2006, up to $3,500,000. Our obligations under this agreement are secured by a security interest in our accounts receivable. Interest on the outstanding amount under the line of credit loan agreement is payable monthly at a rate of prime plus 1.0%. The credit loan agreement provides for non-financial and financial covenants including a minimum debt to worth ratio of 1 to 1.50 and a minimum liquidity of $500,000. As of December 31, 2005, we had no borrowings outstanding under the line of credit loan agreement.

In June of 2005, we completed a $3,366,253 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our second new ARAM ARIES recording system. This loan is repayable over a period of 36 months at a fixed per annum interest rate of 7.25%. This loan is collateralized by the new recording system equipment and the recording vehicles and two semi-trailers that transport the newly purchased equipment between jobs. During the third quarter of 2005, we obtained financing from a commercial lender for $858,705 of the purchase price of three new buggy mounted vibration vehicles for a period of 36 months at a

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fixed per annum simple interest rate of 7.25%. These loans are collateralized by the three new buggy mounted vibration vehicles. In December of 2005, we completed a $3,791,338 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our fourth new ARAM ARIES recording system. This loan is repayable over a period of 36 months at a fixed per annum interest rate of 7.78%. This loan is collateralized by the new recording system equipment.

The board of directors determined to eliminate unnecessary administrative expenses and dividend payments with respect to our outstanding Series C Preferred Stock by redeeming all of such preferred stock. As a result, the board of directors, at its regular meeting held on June 7, 2005, approved the redemption by the Company of the Series C Preferred Stock. The redemption privilege was contained in the resolution establishing such preferred stock. The redemption price was $5.00 per share plus a premium of 40% per share (i.e., $2.00 per share). In addition, each share was entitled to receive the regular $.20 dividend that had accrued for the first half of the year. Thus, the redemption price was $7.20 per share. On June 30, 2005, the Company redeemed all 5,250 shares of its Series C Preferred Stock for $36,750 plus accrued dividends of $1,050.

Our board of directors approved a resolution providing for redemption of all of our outstanding 8½% Senior Convertible Preferred Stock upon the consummation of our public offering in October of 2005. Under the terms of the resolution creating such 8½% Senior Convertible Preferred Stock, each share was redeemable at $1.75 per share, and each holder of our 8½% Senior Convertible Preferred Stock had an option to convert each share of our 8½% Senior Convertible Preferred Stock into one share of our common stock. All of the holders of our 8½% Senior Convertible Preferred Stock elected to convert their shares of 8½% Senior Convertible Preferred Stock into shares of our common stock. As a result, in October of 2005 all of the outstanding shares of our 8½% Senior Convertible Preferred Stock were converted into shares of our common stock.

In October of 2005, the Company completed a public offering of 5,500,000 shares of our common stock at $7.50 per share. In November of 2005, the underwriters of the public offering exercised a portion of their over-allotment option and purchased an additional 285,700 shares of our common stock. The sales resulted in aggregate net proceeds of approximately $40,572,000.

In October of 2001, the Company entered into a three-year operating lease for the Company’s headquarters facility located in Plano, Texas. In April of 2004, the Company executed an addendum to its operating lease. The addendum extended the term of the lease until March 31, 2009, and increased the square footage of the office and outdoor storage area. Additionally, in August of 2005, the Company entered into a 38 month operating lease for additional office and warehouse space in Plano, Texas. This operating lease will expire in October of 2008. In January of 2006, the Company entered into a two-year operating lease for a sales office in Houston, Texas. This operating lease will expire in January of 2008.

Contractual Obligations

The following table summarizes payments due in specific periods related to our contractual obligations as of December 31, 2005:

(1)  See “Capital Resources” above for a discussion of the contractual obligations we have incurred since December 31, 2005.

We believe that our capital resources, including our short-term investments, funds available under our line of credit loan agreement, and cash flow from operations, are adequate to meet our current operational needs. We believe that we will be able to finance our 2006 capital expenditures through cash flow from operations, borrowings from commercial lenders, and the proceeds from our public offering completed in October of 2005. However, our ability to satisfy working capital requirements, meet debt repayment obligations, and fund future capital requirements will depend principally upon our future operating performance, which is subject to the risks inherent in our business.

Off-Balance Sheet Arrangements

As of December 31, 2005, we had no off-balance sheet arrangements.

Critical Accounting Policies

The preparation of our financial statements in conformity with GAAP 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

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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.

Revenue Recognition.

Our services are provided under cancelable service contracts. These contracts are either “turnkey” or “term” agreements. The Company recognizes revenues when services are performed under both types of agreements. Services are defined as the commencement of seismic data acquisition. 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 customer for services performed up to the date of cancellation.

In some instances, we bill customers in advance of the services performed. In those cases, we recognize the liability as deferred revenue.

Allowance for Doubtful Accounts.

We prepare our allowance for doubtful accounts receivable based on our past experience of historical write-offs, our current customer base and our review of past due accounts. The inherent volatility of the energy industry’s business cycle can cause swift and unpredictable changes in the financial stability of our customers.

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 net cash flows are insufficient to recover the carrying value of the asset. Our forecast of future cash flows used to perform impairment analysis includes estimates of future revenues and profitability based on our historical results and analysis of future oil and natural gas prices which is fundamental in assessing demand for our services. If we are unable to achieve these cash flows, our estimates would be revised which could result in an impairment charge for the period of revision.

Depreciable Lives of Property, Plant, and Equipment.

Our property, plant, and equipment are 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. The technology of the equipment used to gather data in the seismic industry has historically evolved such that obsolescence does not occur quickly. As circumstances change and new information becomes available, these estimates could change. We amortize these capitalized items using the straight-line method. Capital assets are depreciated over their useful lives ranging from one to seven years, depending on the classification of the asset.

Tax Accounting.

We account for our income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes,” which requires the recognition of amounts of taxes payable or refundable for the current year and 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, and reducing the deferred tax asset 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 variance between actual results and estimates. This process involves making forecasts of current and future years’ taxable income, and unforeseen events may significantly affect these estimates. Those factors, among others, could have a material impact on our provision or benefit for income taxes.

Stock Based Compensation.

In accordance with the Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” we do not record compensation for stock options or other stock-based awards that are granted to employees or non-employee directors with an exercise price equal to or above the common stock market price on the grant date.

Recently Issued Accounting Pronouncements

In December of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share Based Payment” (SFAS 123R), which requires that compensation costs relating to share-based payments be recognized in our financial statements. We currently account for those payments under the recognition and measurement principles of APB Opinion No. 25, “Accounting for

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Stock Issued to Employees,” and related interpretations. The Company implemented this standard effective January 1, 2006. Such implementation is expected to have minimal impact on our results of operations, financial position, and liquidity.

In December of 2004, the FASB issued SFAS No. 153, “Exchange of Nonmonetary Assets,—an Amendment of APB Opinion No. 29,” (SFAS 153), which became effective for our asset-exchange transactions on July 1, 2005. Under APB 29, assets received in certain types of nonmonetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by SFAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, we have not engaged in significant amounts of nonmonetary asset exchanges.

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 two years.

Qualitative and Quantitative Disclosure about Market Risk

We have not entered into any hedging agreements or swap agreements. Our principal market risk is the risk related to the concentration of our customers in the oil and natural gas industry. Since all of our customers are involved in the oil and natural gas industry, there may be a positive or a negative effect on our exposure to credit risk in that our customers may be similarly affected by changes in economic and industry conditions. For the years ended December 31, 2005 and 2004, our top two customers in each of those years accounted for approximately 11.6% and 10.6% and 33.6% and 14.8%, respectively, of our annual revenues.

FORWARD-LOOKING STATEMENTS

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

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

•       the unpredictable nature of forecasting weather;

•       the potential for contract delay or cancellation;

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

•       the availability of capital resources.

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

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

MARKET DATA AND FORECASTS

Unless otherwise indicated, information in this Form 10-KSB concerning economic conditions and our industry is based on information from independent industry analysts and publications as well as our estimates. Our estimates are derived from publicly available information released by third-party sources, as well as data from our internal research, and are based on such data and our knowledge of our industry, which we believe to be reasonable. None of the independent industry publications used in this Form 10-KSB were prepared on our or our affiliates’ behalves, and none of the sources cited in this Form 10-KSB has consented to the inclusion of any data from its reports, nor have we sought consent from any of them.

RISK FACTORS

Any investment in our common stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below and the other information included in this Form 10-KSB before purchasing our common stock. Although the risks described below are the risks that we believe are material, they are not the only risks relating to our business and our common stock. Additional risks and uncertainties, including those that are not yet identified or that we currently believe are immaterial, may also

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adversely affect our business, financial condition, or results of operations. If any of the events described below occur, our business and financial results could be materially and adversely affected. The market price of our common stock could decline due to any of these risks, perhaps significantly, and you could lose all or part of your investment.

Company Risks

We have a history of losses, and we may incur losses again.

Although we reported net income (before dividend requirements on preferred stock) of approximately $6,201,000 for the year ended December 31, 2005, we have a history of losses with only three profitable years since 1998. In 2004, we had net income (before dividend requirements on preferred stock) of approximately $2,868,000, and in 2003 we had net income (before dividend requirement on preferred stock) of approximately $555,000. Our ability to be profitable in the future will depend on many factors beyond our control, but primarily on the level of demand for land-based seismic data acquisition services by oil and natural gas exploration and development companies. Even if we do achieve profitability, we may not be able to sustain or increase profitability on a quarterly or annual basis.

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

Our revenues, operating results, and profitability may fluctuate from period to period. These fluctuations are attributable to the level of new business in a particular period, the timing of the initiation, progress, or cancellation of significant projects, higher revenues and expenses on our dynamite contracts, and costs we incur to train new crews we may add in the future to meet increased customer demand. Fluctuations in our operating results may also be affected by other factors that are outside of our control such as permit delays, weather delays, and crew productivity. Oil and natural gas prices are at record highs and have resulted in increasing demand for our services. There can be no assurance that such high prices will continue. The demand for our services will be adversely affected by a significant reduction in oil and natural gas prices. Since our business has high fixed costs, the negative effect of one or more of these factors could trigger wide variations in our operating revenues, EBITDA margin, and profitability from quarter to quarter, which render quarter to quarter comparisons unreliable as an indicator of performance. Due to the factors discussed above, you should not expect sequential growth in our quarterly revenues and profitability.

We are implementing a growth strategy which, if successful, will place significant demands on us and subject us to numerous risks.

Growing businesses often have difficulty managing their growth. If our growth strategy is successful, significant demands will be placed on our management, accounting, financial, information, and other systems and on our business. We will have to expand our management and continue recruiting and employing experienced executives and key employees capable of providing the necessary support. In addition, to manage our anticipated growth we will need to continue to improve our financial, accounting, information, and other systems in order to effectively manage our growth, and in doing so could incur substantial additional expenses that could harm our financial results. We cannot assure you that our management will be able to manage our growth effectively or successfully. Our failure to meet these challenges could materially impair our business.

We are dependent upon significant customers.

We derive a significant amount of our revenues from a small number of oil and natural gas exploration and development companies. During 2005 and 2004, our two largest customers accounted, respectively,  for approximately 22.2% and 48.4% of revenues. While our revenues are derived from a concentrated customer base, our significant customers may vary between years. If we lose one or more major customers in the future, or if one or more customers encounter financial difficulties, our business, financial condition, and results of operations could be materially and adversely affected.

We receive revenues from customers who engage consultants for processing and interpreting the seismic data we provide.

We receive revenues from customers who have engaged consultants to process and interpret their seismic data. Consultants can have an influence in determining which company its customers use to acquire seismic data. A consultant could recommend that its customers consider using other seismic companies.

We face intense competition in our business from companies with greater financial resources.

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

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

Seismic data acquisition technologies historically have steadily improved and progressed, and we expect this progression to continue. Our strategy is to upgrade our seismic data acquisition equipment on a regular basis to maintain our competitive position.

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However, since we are in a capital intensive industry and have limitations on our ability to obtain the financing necessary to enable us to purchase state-of-the-art equipment, some of our competitors may be able to purchase newer equipment when we may not be able to do so.

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

We have limited management depth with the result that the loss, whether by death, departure, or illness, of Wayne A. Whitener, our President and Chief Executive Officer, or other senior executives, could have a material adverse effect on the ability of management to continue operations at the same level of efficiency. We have key man insurance on the life of our President and Chief Executive Officer so that, in the event of his untimely death, we would receive insurance proceeds of $1,000,000 under this policy.

Certain members of our management team are not subject to employment or non-competition agreements and may leave our employment at any time.

None of the members of our management team, other than our President and Chief Executive Officer, are subject to employment agreements or non-competition agreements; therefore, any of these members of our management team could leave upon little or no notice which could have a material adverse effect on our management’s ability to continue operations at the same level of effectiveness. Additionally, the lack of non-competition agreements would allow these members of our management team to immediately begin working for one of our competitors upon the termination of their relationship with us. This could have a negative impact on our strategic plan and our relationships with customers.

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

We perform ongoing credit evaluations of our customers’ financial conditions and, generally, require no collateral from our customers. A default in payment from one of these large customers could have a material adverse effect on our operating revenues for the period involved.

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

Certain assets that are critical to our operations, including three of our ARAM ARIES recording systems, are pledged as collateral to our equipment lenders and could be subject to foreclosure in the event that we default on our indebtedness having 36 month terms. We currently have debt obligations covering the purchase of three of our four ARAM ARIES recording systems that require monthly payments between approximately $67,000 and $82,000 for the first ARAM ARIES recording system, between approximately $94,000 and $114,000 for the second ARAM ARIES recording system, and between approximately $106,000 and $130,000 for the fourth ARAM ARIES recording system. Any decline in our operations could inhibit our ability to make these substantial monthly payments. In light of the short terms of these notes, a failure to make the monthly payments on these notes could cause our lenders to promptly foreclose on the assets securing these notes. The foreclosure of certain of our core assets securing these notes could severely limit our ability to continue operations.

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

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

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

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We do not carry insurance against certain risks that we could experience, including business interruption resulting from equipment maintenance or weather delays. We obtain insurance against certain property and personal casualty risks and other risks when such insurance is available and when our management considers it advisable to do so. Our current insurance coverage consists of employers liability with limits of $1,000,000 per accident and $2,000,000 in the aggregate, commercial general liability of $1,000,000 per accident and $2,000,000 in the aggregate, pollution liability of $1,000,000 per accident and $2,000,000 in the aggregate, automobile liability with a $1,000,000 combined single limit, and a $10,000,000 umbrella policy.

Our general service agreements require us to have specific amounts of insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover all losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a materially adverse effect on us.

We are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, and results of operations and financial condition could be materially adversely affected.

We will be required to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 by December 31, 2007. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls and management’s assessment of those controls. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations, and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our profitability could be affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification, and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report any material weakness, the accuracy and timeliness of the filing of our annual and quarterly reports may be negatively affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing, and require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability, and financial condition.

Industry Risks

We derive all of our revenues from companies in the oil and natural gas exploration and development industry, a historically cyclical industry, with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices.

Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, can adversely impact us in many ways by negatively affecting:

•       our revenues, cash flows, and profitability;

•       our ability to maintain or increase our borrowing capacity;

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

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

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

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

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

•       the rate of decline of existing and new oil and natural gas reserves;

•       available pipeline and other oil and natural gas transportation capacity;

•       the ability of oil and natural gas companies to raise capital;

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

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

•       economic conditions in the U.S. and elsewhere;

•       domestic and foreign tax policy;

•       weather conditions in the U.S. and elsewhere;

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

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

•       the overall supply and demand for oil and natural gas.

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

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

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

Our seismic data acquisition operations could be adversely affected by our inability to obtain timely right of way usage from both public and private land and/or mineral owners. Delays associated with obtaining such rights of way could negatively affect our results of operations.

Our industry has recently experienced shortages in the availability of equipment. Any difficulty we experience replacing or adding equipment could adversely affect our business.

We may not be able to acquire equipment to replace our existing equipment or add additional equipment. The high demand for the services that we provide has decreased the supply of geophysical equipment, resulting in extended delivery dates on orders of new equipment. Any delay in obtaining equipment could delay the implementation of additional crews and restrict the productivity of our existing crews. A delay in obtaining equipment essential to our operations could have a material adverse effect on our operations.

Our business is subject to government 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 the 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. Although such expenditures historically have not been material to us, the fact that such laws or regulations change frequently makes it impossible for us to predict the cost or impact of such laws and regulations on our future operations. The adoption of laws and regulations that have the effect of reducing or curtailing exploration and development activities by energy companies could also adversely affect our operations by reducing the demand for our services.

Risks Related To Our Common Stock

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

Our stock price is subject to significant volatility. Overall market conditions including a decline in oil and natural gas prices, in addition to other risks and uncertainties described in this “Risk Factors” section and elsewhere in this Form 10-KSB, may cause the market price of our common stock to fall. Our high and low closing stock prices for the 12 months ended December 31, 2005, were $11.70 and $2.72, respectively.

Our common stock is listed on the American Stock Exchange under the symbol “TGE.” However, daily trading volumes for our common stock are, and may continue to be, relatively small compared to many other publicly traded securities. For example, since April 18, 2005, when we began trading on the American Stock Exchange, our daily trading volume has been as low as 1,600 shares. It may be difficult for you to sell your shares in the public market at any given time at prevailing prices, and the price of our common stock may, therefore, be volatile.

Our officers and directors own a large percentage of our common stock, and they may control our business and affairs.

Our officers and directors as a group beneficially own approximately 33.7% of our common stock. As a result, they will continue to be able to exercise significant influence, and in most cases control, over matters requiring shareholder approval, including the

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election of directors, changes to our charter documents, and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The continued concentrated ownership of our common stock will make it difficult for another company to acquire us and for you to receive any related takeover premium for your shares (unless the controlling group approves the acquisition).

Certain provisions of our Restated Articles of Incorporation may make it difficult for a third party to acquire us or may adversely impact your rights as a common shareholder.

Our Restated Articles of Incorporation contain provisions that require the approval of holders of 80% of our issued and outstanding shares before we can enter into a merger or other business combination or sell all or substantially all of our assets. Additionally, if we increase the size of our board from the current six to nine directors, we could be required to stagger our directors’ terms, and our directors could not be removed without approval of holders of 80% of our issued and outstanding shares. These provisions could discourage or impede a tender offer, proxy contest, or other similar transaction involving control of us.

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

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

While there are currently no restrictions prohibiting us from paying dividends to our shareholders, we have not paid any cash dividends on our common stock in the past, and we do not anticipate paying any dividends in the foreseeable future. Payment of any cash dividends in the future, however, is in the discretion of our board of directors and will depend on our financial condition, results of operations, capital and legal requirements, and other factors deemed relevant by our board of directors. Earnings, if any, are expected to be retained to fund our future operations.

ITEM 7. FINANCIAL STATEMENTS.

Financial Statements

December 31, 2005 and 2004

CONTENTS

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Report of Independent Registered Public Accounting Firm

Board of Directors and

Shareholders of TGC Industries, Inc.

We have audited the accompanying balance sheets of TGC Industries, Inc. as of December 31, 2005 and 2004, and the related statements of income, stockholders’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audits 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 financial statements referred to above present fairly, in all material respects, the financial position of TGC Industries, Inc. as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

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TGC Industries, Inc.

BALANCE SHEETS

December 31,

The accompanying notes are an integral part of these statements.

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The accompanying notes are an integral part of these statements.

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TGC Industries, Inc.

STATEMENTS OF INCOME

Year Ended December 31,

The accompanying notes are an integral part of these statements.

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TGC Industries, Inc.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Years Ended December 31, 2005 and 2004

The accompanying notes are an integral part of these statements.

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TGC Industries, Inc.

STATEMENTS OF CASH FLOWS

Year Ended December 31,

The accompanying notes are an integral part of these statements.

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TGC Industries, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005 and 2004

NOTE A - NATURE OF OPERATIONS

TGC Industries, Inc. (TGC or the Company) is engaged in the domestic geophysical services business and primarily conducts seismic surveys and sells gravity data to companies engaged in exploration in the oil and gas industry.

NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash Equivalents

The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The Company maintains its accounts at financial institutions located in Texas. The bank accounts are insured by the Federal Deposit Insurance Corporation up to $100,000.

Trade Receivables

Trade accounts receivable are recorded in accordance with terms and amounts as specified in the related contracts on an ongoing basis. The Company evaluates the collectibility of accounts receivable on a specific account basis using a combination of factors, including the age of the outstanding balances, evaluation of the customer’s financial condition, and discussions with relevant Company personnel and with the customers directly. An allowance for doubtful accounts or direct write-off is recorded when it is determined that the receivable may not be collected, depending on the facts known and the probability of collection of the outstanding amount.

Property and Equipment

Property and equipment are stated at cost. Depreciation and amortization are provided using the straight-line method over the estimated useful lives of the individual assets ranging from 1 to 7 years. The amortization expense on assets acquired under capital leases is included with depreciation and amortization expense on owned assets. Expenditures for major renewals and betterments that extend the useful lives of property and equipment are capitalized. Expenditures for maintenance and repairs are charged to expenses as incurred.

Long-Lived Assets

Long-lived assets held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For the purposes of evaluating the recoverability of long-lived assets, the recoverability test is performed using undiscounted cash flows estimated to be generated by those assets.

Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amounts of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

Revenue Recognition

Revenues from conducting seismic surveys are recognized over the term of the contract using the percentage-of-completion method. Under this method, revenues are recognized on the units-of-production method. Revenues for the sale of gravity data are recognized when services are rendered.

Reclassifications

Certain reclassifications have been made to the 2004 financial statements to conform to the 2005 presentation.

Stock-Based Compensation

The Company has one stock-based employee compensation plan, which is described more fully in Note H. The Company accounts for this plan under the recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under this plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and income per share allocable to common stockholders if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board (“FASB”) Statement No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation”, to stock-based employee compensation:

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The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants in 2005: risk-free interest rate of 4.20%, expected dividend yields of 0.0%, expected lives of 5.0 years; and expected volatility of 92.72% in 2005 and 96.5% in 2004.

Financial Instruments

The Company’s financial instruments recorded on the balance sheet include cash and cash equivalents, accounts receivable, accounts payable and debt. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of the short-term nature of these items. Fair value of long-term debt is based on rates available to the Company for debt with similar terms and maturities.

Earnings Per Share

Basic earnings per common share is based upon the weighted average number of shares of common stock outstanding. Diluted earnings per share is based upon the weighted average number of common shares outstanding and, when dilutive, common shares issuable for stock options, warrants and convertible securities.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America 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. Actual results could differ from those estimates.

Recent Accounting Standards

In December 2004, the FASB issued FASB Statement No.123R, “Share-Based Payment” (SFAS 123R), which requires that compensation costs relating to share-based payments be recognized in the Company’s financial statements. The Company currently accounts for those payments under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company is preparing to implement this standard effective January 1, 2006. Although the transition method to be used to adopt the standard has not been selected, the impact of adoption is expected to have a minimal impact on the Company’s results of operations, financial position and liquidity. Refer to Note H, for the Company’s calculation of the pro forma impact on net income of SFAS 123, which would be similar to that under SFAS 123R.

In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, – an Amendment of APB Opinion No. 29,” (SFAS 153), which is effective for the Company for asset-exchange transactions beginning July 1, 2005. Under APB 29, assets received in certain types of nonmonetary exchanges were permitted to be recorded at the carrying value of the assets that were exchanged (i.e., recorded on a carryover basis). As amended by SFAS 153, assets received in some circumstances will have to be recorded instead at their fair values. In the past, the Company has not engaged in nonmonetary asset exchanges for significant amounts.

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NOTE C - COSTS AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

The components of uncompleted contracts are as follows at December 31,:

The components of uncompleted contracts are reflected in the balance sheets at December 31, 2005 and 2004 as follows:

NOTE D - ACCRUED LIABILITIES

Accrued liabilities consist of the following at December 31,:

NOTE E - DEBT

Line of Credit

On August 2, 2004, the Company obtained a line of credit from a bank with a $500,000 credit limit. The line of credit accrued interest at the bank’s prime rate plus 1% and per the credit loan agreement matured on August 2, 2005. Collateral for this line of credit was accounts receivable. Advances were limited to eligible receivables. There were no advances made under this line of credit and the company terminated this line of credit in May 2005.

In April 2005, the Company entered into a revolving line of credit arrangement with a bank, providing for borrowings of up to $500,000. On September 16, 2005, the company amended the revolving line of credit allowing the company to borrow, repay and re-borrow, from time to time up to $3,500,000. The revolving line of credit is secured by a security interest in the company’s accounts receivable and matures in September 2006. Interest on the outstanding amount under the line of credit loan agreement is payable monthly at a rate of prime plus 1%. The credit loan agreement provides for non-financial and financial covenants, including a minimum debt to worth ratio of 1 to 1.50 and a minimum liquidity of $500,000. At December 31, 2005, the company had no borrowings outstanding under the line of credit loan agreement.

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Notes Payable

Notes payable consist of the following at December 31:

None of the above notes require the maintenance of financial ratios.

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Aggregate annual maturities of notes payable at December 31, 2005 are as follows: