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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the transition period from                  to                   .

Commission File Number 01-14908

TGC INDUSTRIES, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:  (972) 881-1099

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

Securities registered pursuant to Section 12(g) of the Act: None

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

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

Large accelerated filer o  Accelerated filer x  Non-accelerated filer o Smaller reporting company o

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 last sold as of the last business day of the Registrant’s most recently completed second  fiscal quarter was $112,220,919.

Number of shares of Common Stock outstanding as of February 27, 2009:  17,396,017

Documents incorporated by reference

Listed below are documents, parts of which are incorporated herein by reference, and the part of this report into which the document is incorporated:

Proxy statement for the 2009 annual meeting of shareholders – Part III

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Part I

ITEM 1. BUSINESS.

General

TGC Industries, Inc. (“TGC” or the “Company”) is a Texas corporation primarily engaged in the geophysical service business of conducting Three-D (“3-D”) surveys for clients in the oil and gas business.  TGC’s principal business office is located at 101 E. Park Blvd., Suite 955, Plano, Texas 75074 (Telephone: 972-881-1099).  TGC’s internet address is www.tgcseismic.com.  TGC makes available free of charge on its website its annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as soon as reasonably practicable after filing or furnishing such information with the Securities and Exchange Commission.

History

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

We are a leading provider of seismic data acquisition services throughout the continental United States. As of December 31, 2008, we operated nine seismic crews.  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 acquire and process, on a cost-effective basis, immense volumes of seismic data which produce precise images of the earth’s subsurface. The latest accepted method of seismic data acquisition, processing, and the subsequent interpretation of the processed data is the 3-D seismic method. Geophysicists use computer workstations to interpret 3-D data volumes, identify subsurface anomalies, and generate a geologic model of subsurface features.

3-D seismic data are used in the exploration and development 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., Petroleum Geo Services, and, to a lesser extent, CGG-Veritas.  These

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companies field approximately 50% of the estimated 65 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 types of operations.

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 levels 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.

Equipment and Crews

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.    In May of 2006, we deployed our seventh seismic data acquisition crew along with our fifth new ARAM ARIES recording system.  In October of 2006, we deployed our eighth seismic data acquisition crew along with our sixth new ARAM ARIES recording system.  In December of 2007, we completed a loan transaction with a commercial lender for the purpose of providing funds for the purchase of our seventh new ARAM ARIES recording system.  In January 2008, the Company entered into an agreement with a bank to provide financing for the purchase of new vibration vehicles.  In February 2008, the Company exercised its purchase option for seismic recording equipment it had been renting.  In March 2008, the Company entered into a loan agreement with a commercial lender to provide financing for purchase of this rented equipment and to replace an existing loan the Company had with the lender.  In July 2008, the Company entered into a loan agreement with a bank to provide financing for the purchase of additional seismic recording equipment.  In August 2008, the Company entered into a loan agreement with a bank to provide financing for the purchase of new vibration vehicles.  In September 2008, the Company entered into a loan agreement with a commercial lender to provide financing for the purchase of a new seismic recording system and equipment.  In December 2008, we deployed our ninth seismic data acquisition crew along with our eighth new ARAM ARIES recording system.

Eight of our crews utilize the 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.  The other crew utilizes the Opseis Eagle data gathering system. This system employs radio-frequency 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.

We currently own equipment for nine land-based seismic data acquisition crews and 60 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.

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 2008, capital expenditures were approximately $21,686,000 compared with approximately $18,238,000 for 2007.  The capital expenditures in 2008 were primarily for equipment and equipment maintenance to meet the increased demand from our customers.

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

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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 many 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.

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

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 30 days’ advance written notice, is entered into for every project. We currently operate under supplemental agreements that are either “turnkey” agreements providing for a fixed fee to be paid to us for each unit of data acquired or “term” agreements providing for a fixed hourly, daily, or monthly fee during the term of the project or projects.

Competition

The acquisition of seismic data for the oil and natural gas industry is a highly competitive business. There are approximately 65 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 and technological and operational expertise, are often determinative. Our competitors include companies with financial resources that are significantly greater than our own as well as companies of comparable and smaller size. Our primary competitors are Dawson Geophysical Company, Geo Kinetics, Inc., Petroleum Geo Services, and to a lesser extent, CGG-Veritas.  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.

Employees

As of December 31, 2008, we employed a total of 651 full-time (non-union) employees, of which 17 consisted of management, sales, and administrative personnel with the remainder being crew and crew support 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 United States. 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 activities can cause personal injury or loss of life, damage to or destruction of property, equipment, the environment, and marine life, and suspension of operations.

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

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We do not carry insurance against certain risks that we could experience such as business interruption resulting from equipment maintenance or weather delays. We obtain insurance against certain property and personal casualty risks and other risks when such insurance is available and when our management considers it advisable to do so. 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, and 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 1A.  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-K 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 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 of approximately $6,898,000, $7,607,000 and $8,111,000 for the years ended December 31, 2008, 2007 and 2006, respectively, we have a history of losses with only six profitable years since 1998.  In 2005, we had net income (before dividend requirements on preferred stock) of approximately $6,201,000, 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 requirements 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.

The current economic downturn could adversely affect our revenues and cash flows.

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

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 were highly volatile during the year ended December 31, 2008, and have resulted in demand fluctuations for our services. There can be no assurance of future oil and gas price levels or stability.  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 factors render quarter-to-quarter comparisons unreliable as an indicator of performance.  Due to the factors discussed above, you should not expect sequential growth in our quarterly revenues and profitability.

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We are dependent upon significant customers.

During 2008, our two largest customers accounted for approximately 27% of revenues.  During 2007 our two largest customers accounted for approximately 22% of revenues.  During 2006 no customer accounted for 10% of our revenues.  In the past we have derived a significant amount of our revenues from a small number of oil and natural gas exploration and development companies.  While our revenues are derived from a concentrated customer base, our significant customers 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 the seismic data provided by us. 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. 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.

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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 two of our ARAM ARIES recording systems and 13 vibration vehicles are pledged as collateral to our equipment lenders and commercial banks and could be subject to foreclosure in the event that we default on our indebtedness having 36 to 57 month terms. We currently have debt obligations covering the purchase of two of our eight ARAM ARIES recording systems that require monthly payments between approximately $86,000 and $108,000 for the seventh ARAM ARIES recording system, and between approximately $80,000 and $98,000 for the eighth ARAM ARIES recording system.  These debt obligations mature in December 2011 and October 2012, respectively.  The Company also has debt obligations covering the purchase of five vibration vehicles requiring monthly payments between approximately $56,000 and $65,000, and the purchase of eight vibration vehicles, requiring monthly payments of approximately $50,000.  These debt obligations mature in August 2011 and February 2013, respectively.  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 on 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 contained in our general service agreements to the extent that the damage is due to our negligence or intentional misconduct.

We do not carry insurance against certain risks that could cause losses, including business interruption resulting from equipment maintenance or weather delays. 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, and 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 maintain compliance with Section 404 or if the costs related to maintaining compliance are significant, our profitability, stock price, and results of operations and financial condition could be materially adversely affected.

If we are unable to maintain adequate internal controls, in accordance with Section 404, as such standards are amended, supplemented, or modified from time to time, we may not be able to ensure that we have effective

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internal controls over financial reporting in accordance with Section 404 on an ongoing basis.  Failure to achieve and maintain effective internal controls could have a material adverse effect on our stock price.  In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing, and/or require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability, and financial condition.

Industry Risks

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

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

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, could adversely impact us in many ways by negatively affecting:

·                  our revenues, cash flows, and profitability;

·                  our ability to maintain or increase our borrowing capacity;

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

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

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

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

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

·                  the 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;

·                  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;

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·                  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 consist primarily of depreciation (a non-cash item) and maintenance expenses associated with seismic data acquisition and equipment and crew costs. In addition, ongoing maintenance capital expenditures, as well as new equipment investment, can be significant. As a result, any extended periods of significant downtime or low productivity caused by reduced demand, weather interruptions, equipment failures, permit delays, or other causes could adversely affect the results of our 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 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-K, could cause the market price of our common stock to fall. The high and low sales prices of our common stock for the year ended December 31, 2008, were $10.17 and $1.05, respectively.

Our common stock is listed on the NASDAQ Stock Market LLC 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, during 2008, our daily trading volume was as low as 4,800 shares.  Since November 6, 2007, when we began trading on the NASDAQ Stock Market LLC, our daily trading volume has been as low as 2,800 shares.  In addition, our common stock traded on the NYSE Alternext US (formerly the American Stock Exchange) under the symbol “TGE” from April 18, 2005 until November 5, 2007.  During this period of time our daily trading volume was 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.

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

Our officers and directors as a group beneficially own approximately 28.7% 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 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 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. DESCRIPTION OF PROPERTY.

In April of 2004, we executed an addendum to our lease of a facility in Plano, Texas, that included approximately 10,500 square feet of office and warehouse space and an outdoor storage area of approximately 20,000 square feet.  This facility was used to repair geophysical equipment and housed our corporate offices until September of 2006.  In September of 2005, we leased an additional facility, in Plano, Texas, with approximately 10,000 square feet of office and warehouse space and an additional 10,000 square feet of outdoor storage to accommodate our growth.  This facility was used primarily to repair geophysical equipment.  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 $553.    In July of 2006, we entered into a lease for 7,269 square feet of office space located in Plano, Texas.  In September of 2006, we relocated our corporate offices to this facility, and in September 2008 increased the size of this lease to 8,523 square feet of office space.  The monthly rent is $12,127.  In October of 2006, we leased an 800 square foot facility in Oklahoma City, Oklahoma, to be used as a sales office.  The monthly rent is $665.  In September of 2007, we leased a 1,130 square foot facility in Denver, Colorado, to be used as a sales office.  The monthly rent is $2,284.  In September 2008, we leased a 400 square foot facility is Pratt, Kansas, to be used as a permit office.  The monthly rent is $500.  In November 2008, we vacated our two Plano repair, warehouse and outdoor storage facilities, and moved to a leased repair, warehouse and outdoor storage facility in Denison, Texas.  The Denison, Texas, facility consists of one 5,000 square foot building, two 10,000 square foot adjacent buildings and an outdoor storage area of approximately 60,500 square feet.  The monthly rent is $15,607.  The Company is not responsible for insuring these

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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.

The Company is a defendant in various legal actions that arose or may arise out of the normal course of business.  In our opinion, none of these actions have or will result in any significant loss to us.

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, 2008, to a vote of our security holders through the solicitation of proxies or otherwise.

PART II

ITEM 5. MARKET FOR REGISTRANT’S EQUITY, AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

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 NYSE Alternext US (formerly the American Stock Exchange) (“AMEX”) on April 18, 2005, under our current trading symbol “TGE.”  On October 26, 2007, we announced that our board of directors approved the decision to switch the listing of our common stock from AMEX to the NASDAQ Global Select Market (“NASDAQ.”)  As a result, on November 6, 2007, our stock began trading on NASDAQ under the symbol “TGE.”

In the following table, the prices shown through November 5, 2007, represent the high and low sales prices reported for our common stock on AMEX.  Beginning on November 6, 2007, the following table shows the high and low sales prices reported for our common stock on NASDAQ.  On April 28, 2008 and April 27, 2007, the Company paid 5% stock dividends to shareholders of record at the close of business on April 14, 2008 and April 13, 2007, respectively.  All prior share and per share amounts have been restated to reflect the stock dividends.

The number of shareholders of record of TGE’s common stock as of February 27, 2009, was 155.  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 14,107,855 shares in street name.  On February 27, 2009, our common stock was quoted at a closing sales price of $1.95.

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.

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The following table summarizes certain information regarding securities authorized for issuance under our equity compensation plans as of December 31, 2008.  See information regarding material features of the plans in Note H, ‘Shareholders’ Equity-Stock-Based Compensation Plans” to the Financial Statements included herein.

Equity Compensation Plan Information

(1)  No shares remain available to be issued under the 1999 Stock Option Plan.  There are 388,770 shares available to be issued under the 2006 Stock Award Plan.

Performance Graph

The following graph is not “soliciting material,” is not deemed filed with the Securities and Exchange Commission, and is not to be incorporated by reference into any of the Company’s filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, respectively.

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The following graph sets forth the five-year cumulative total shareholder return, which assumes reinvestment of dividends, of a $100 investment beginning in the Company’s common stock, a peer group made up of companies in the Philadelphia Oil Service Sector Index, and the S&P 500 Stock Index.  The Philadelphia Oil Service Sector Index consists of far larger companies that provide a variety of services as compared to the land-based geophysical services provided by the Company.

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ITEM 6. SELECTED FINANCIAL DATA.

The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the Company’s financial statements and notes thereto included in Item 8, “Financial Statements and Supplementary Data.”  No cash dividends were declared in any of the five years shown below:

In October of 2005, the Company completed a public offering of approximately 5,786,000 (not adjusted for the 5% stock dividends paid in 2008, 2007 and 2006) shares of common stock.  The weighted average number of equivalent common shares outstanding in 2005 reflect these additional shares for a portion of the year.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION.

The following discussion and analysis should be read in conjunction with our financial statements and related notes thereto included elsewhere in this Form 10-K. 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-K should be read as applying to all related forward-looking statements wherever they appear in this Form 10-K. 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 “Business,” “Information Regarding Forward-Looking Statements,” and “Risk Factors.”

Executive Overview

The Company is a leading provider of seismic data acquisition services throughout the continental United States.  We currently operate nine seismic crews.  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

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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.

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 which field numerous crews and work in a number of different regions and terrain.  This group includes us, Dawson Geophysical Company, Geo Kinetics, Inc., Petroleum Geo Services, and to a lesser extent CGG-Veritas. These companies field approximately 50% of the estimated 65 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 types 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.

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 sales, 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.

The acquisition of seismic data for the oil and natural gas industry is a highly competitive business. There are approximately 65 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, and technological and operational expertise, are often determinative. Our competitors include companies with financial resources that are significantly greater than our own as well as companies of comparable and smaller size. Our primary competitors are Dawson Geophysical Company, Geo Kinetics, Inc., Petroleum Geo Services, and to a lesser extent, CGG-Veritas. 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 customer relationships developed over our history, and our financial stability give us an advantage over most of our competitors in the industry.

Results of Operations

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenues.  Our revenues were $86,769,742 for the year ended December 31, 2008 compared to $90,395,872 for the same period of 2007, a decrease of 4%.  This decrease in revenues was attributable to the fact that approximately 20% of the revenues in the year ended December 31, 2008 were derived from shot-hole contracts compared with approximately 34% for the same period of 2007.  Shot-hole contracts typically generate higher revenues but lower gross margins than vibroseis contracts due to higher third party costs that are included in revenues and have little or no margin associated with them.

Cost of services.  Our cost of services was $55,935,068 for the year ended December 31, 2008 compared to $60,445,783 for the same period of 2007, a decrease of 7.5%.  This decrease was primarily attributable to the decrease in revenues in the year ended December 31, 2008 compared to the same period of 2007, and higher third party costs associated with the additional shot-hole contracts in 2007 compared to 2008.  As a percentage of revenues, cost of services was 64.5% for the year ended December 31, 2008 compared to 66.9% for the same period of 2007.

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Selling, general, and administrative expenses.  SG&A expenses were $4,468,883 for the year ended December 31, 2008 compared to $3,864,810 for the same period of 2007, an increase of 15.6%.  This increase was primarily attributable to additional expenses associated with additional selling and administrative personnel, and additional compensation expense for deferred stock-based compensation.  SG&A expense as a percentage of revenues was 5.2% for the year ended December 31, 2008 compared to 4.3% for the same period of 2007.

Depreciation and amortization expense.  Depreciation and amortization expense was $13,911,124 for the year ended December 31, 2008 compared to $12,743,065 for the same period of 2007, an increase of 9.2%.  This increase was primarily attributable to depreciation and amortization expense associated with capital expenditures of approximately $21,686,000 since January 1, 2008.  This increase was partially offset by a decrease in depreciation expense in the third and fourth quarters of 2007 and the first and second quarters of 2008 as a result of an increase in the estimated useful life of certain seismic equipment.  See “Change In Accounting Estimate” in Note B of Notes to Financial Statements in Item 8.  Depreciation and amortization expense as a percentage of revenues was 16.0% for the year ended December 31, 2008 compared to 14.1% for the same period of 2007.

Income from operations.  Income from operations was $12,454,667 for the year ended December 31, 2008 compared to $13,342,214 for the same period of 2007, a decrease of 6.7%.  This decrease was primarily attributable to a decrease in revenues, an increase in SG&A and depreciation and amortization expenses, partially offset by a decrease in costs of services.  EBITDA increased $280,512 to $26,365,791 for the year ended December 31, 2008 from $26,085,279 for the same period of 2007, an increase of 1.1%.  This increase was primarily attributable to the increase in depreciation referred to immediately above.  For a definition of EBITDA, a reconciliation of EBITDA to net income, and discussion of EBITDA, see the section entitled “Non-GAAP Financial Measure” which follows.

Interest expense.  Interest expense was $929,656 for the year ended December 31, 2008 compared to $604,616 for the same period of 2007, an increase of 53.8%.  This increase was primarily attributable to the additional debt incurred in 2008 as a result of financing certain new seismic equipment purchased during 2008.

Income tax expense.  Income tax expense was $4,626,569 for the year ended December 31, 2008 compared to $5,130,165 for the same period of 2007, a decrease of 9.8%.  The effective tax rate for the year ended December 31, 2008 was 40.1% compared to 40.3% for the same period of 2007.

Year Ended December 31, 2007, Compared to Year Ended December 31, 2006

Revenues.  Our revenues were $90,395,872 for the year ended December 31, 2007 compared to $67,760,306 for the same period of 2006, an increase of 33.4%.  This increase in revenues was attributable to several factors, including operating eight seismic data acquisition crews for 12 months in 2007 compared with six crews the first four months, seven crews for the next five months and eight crews for the last three months of the same period of 2006, as well as the fact that approximately 34% of revenues in the year ended December 31, 2007 were derived from lower margin shot-hole contracts compared with approximately 25% for the same period of 2006.  These shot-hole contracts typically generate higher revenues but lower gross margins than vibroseis contracts due to higher third party costs that are included in revenues and have little or no margin associated with them.

Cost of services.  Our cost of services was $60,445,783 for the year ended December 31, 2007 compared to $40,831,650 for the same period of 2006, an increase of 48%.  This increase was attributable to several factors:  (1) the increase in revenues in the year ended December 31, 2007 compared to the same period of 2006; (2) the adverse weather conditions in January and February 2007 in Colorado and Kansas; (3) the severe flooding conditions in the Mid-continent and Southwestern areas of the United States during the second quarter of 2007; (4) severe weather conditions in July 2007 that negatively impacted our revenue by approximately 18% and our pretax income by approximately 62%; and (5) the higher third party costs associated with the additional shot-hole contracts in 2007 compared to 2006.  As a percentage of revenues, cost of services was 66.9% for the year ended December 31, 2007 compared to 60.3% for the same period of 2006.

Selling, general, and administrative expenses.  SG&A expenses were $3,864,810 for the year ended December 31, 2007 compared to $2,988,892 for the same period of 2006, an increase of 29.3%.  This increase was primarily attributable to additional expenses associated with additional selling and administrative personnel, additional compensation expense for deferred stock-based compensation, increased insurance costs, and additional expenses associated with the operation of eight crews during the entire year of 2007 compared to six crews the first four months, seven crews the next five months, and eight crews for the last three months of the same period of 2006.

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SG&A expense as a percentage of revenues was 4.3% for the year ended December 31, 2007 compared to 4.4% for the same period of 2006.

Depreciation and amortization expense.  Depreciation and amortization expense was $12,743,065 for the year ended December 31, 2007 compared to $9,540,171 for the same period of 2006, an increase of 33.6%.  This increase was primarily attributable to depreciation and amortization expense associated with capital expenditures of approximately $18,200,000 since January 1, 2007.  This increase was partially offset by a decrease in depreciation expense in the third and fourth quarters of 2007 as a result of an increase in the estimated useful life of certain seismic equipment.  See “Change In Accounting Estimate” in Note B of Notes to Financial Statements in Item 8.  Depreciation and amortization expense as a percentage of revenues was 14.1% for the fiscal years of 2007 and 2006.

Income from operations.  Income from operations was $13,342,214 for the year ended December 31, 2007 compared to $14,399,593 for the same period of 2006, a decrease of 7.3%.  This decrease was primarily attributable to the increase in cost of services, SG&A, and depreciation and amortization expense, partially offset by an increase in revenues.  EBITDA increased $2,145,515 to $26,085,279 for the year ended December 31, 2007 from $23,939,764 for the same period of 2006, an increase of 9%.  This increase was primarily attributable to the increase in gross margin.  For a definition of EBITDA, a reconciliation of EBITDA to net income, and discussion of EBITDA, see the section entitled “Non-GAAP Financial Measure” which follows.

Interest expense.  Interest expense was $604,616 for the year ended December 31, 2007 compared to $780,782 for the same period of 2006, a decrease of 22.6%.  This decrease was primarily attributable to the reduction of debt.

Income tax expense.  Income tax expense was $5,130,165 for the year ended December 31, 2007 compared to $5,507,386 for the same period of 2006, a decrease of 6.8%.  The effective tax rate for the year ended December 31, 2007 was 40.3% compared to 40.4% for the same period of 2006.

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.

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 Principles (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.

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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 $33,860,082 for the year ended December 31, 2008, compared to $14,839,414 for the same period of 2007.  The $19,020,668 increase was principally attributable to the timing of accounts receivable collections, the timing of receipt and payment of invoices and taxes, and the timing of billings and revenue recognition.  Changes in significant components of net cash provided by operations were a $708,991 change in net income, a $1,168,059 change in depreciation and amortization expense, a $2,995,031 change in deferred income taxes, a $11,004,486 change in trade accounts receivable, a $2,220,150 change in costs and estimated earnings in excess of billings on uncompleted contracts, a $3,659,368 change in trade accounts payable, a $1,473,377 change in accrued liabilities, a $1,202,070 change in prepaid federal and state income taxes, and a $5,255,518 change in billings in excess of costs and estimated earnings on uncompleted contracts.

Working capital increased $11,479,746 to $16,969,043 as of December 31, 2008, from the December 31, 2007, working capital of $5,489,297.  This increase was due primarily to an increase in cash and cash equivalents of $19,610,525, an increase in prepaid income taxes of $1,119,736, a decrease in accrued liabilities of $860,322, partially offset by a decrease in trade accounts receivable of $6,299,590, an increase in trade accounts payable of $1,638,647, an increase in billings in excess of costs and estimated earnings on uncompleted contracts of $2,436,224, and an increase in current maturities of notes payable of $1,869,969.

Cash flows used in investing activities.

Net cash used in investing activities was $6,078,536 for the year ended December 31, 2008, and $12,661,703 for the year ended December 31, 2007.  The $6,583,167 decrease was mainly due to a decrease in cash related capital expenditures during 2008 of $6,686,040.

Cash flows used in financing activities.

Net cash used in financing activities was $8,171,021 for the year ended December 31, 2008, and $7,062,654 for the year ended December 31, 2007.  The $1,108,367 increase was due primarily to an increase in principal payments on notes payable of $1,277,274.

Capital expenditures.

During the year ended December 31, 2008, capital expenditures of $21,685,982 were used to acquire additional seismic equipment and vehicles.  This additional seismic equipment primarily included two new ARAM ARIES recording systems, additional recording channels for our ARAM ARIES recording crews, and 13 new vibration vehicles for our recording crews.  The additional seismic equipment and vehicles were primarily to enhance the efficiency of our existing crews and to equip our ninth crew.  During the first two months of 2009, there have been no material capital expenditures.  Although we do not budget for our capital expenditures, we may purchase additional equipment during 2009 as the demand for our services warrants.

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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.

In April of 2005, we entered into a revolving credit agreement with a commercial bank.  Effective September 16, 2006, we renewed our revolving credit agreement and increased the borrowing limit from $3,500,000 to $5,000,000. The borrowing limit under the revolving line of credit agreement remains at $5,000,000 and was renewed on September 16, 2007, and again on September 16, 2008.  The revolving line of credit agreement does not expire until September 16, 2009.  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 the prime rate of interest. The credit loan agreement provides for non-financial and financial covenants including a minimum debt service coverage ratio in excess of 2.0 to 1.0, a ratio of debt to worth not in excess of 1.25 to 1.0.  As of December 31, 2008, we had no borrowings outstanding under the line of credit loan agreement.

In December of 2007, we completed a $4,120,254 loan transaction with a commercial lender for the purpose of providing funds for the purchase of our seventh new ARAM ARIES recording system. This loan is repayable over a period of 48 months at a fixed per annum interest rate of 6.38%. 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.  In January 2008, the Company entered into a $2,463,101 loan agreement with a bank to provide financing for the purchase of new vibration vehicles.  The loan is repayable over a period of 57 months at a fixed per annum interest rate of 6.35% and is collateralized by the vibration vehicles.  In February 2008, the Company exercised its purchase option for seismic recording equipment it had been renting.  In March 2008, the Company entered into a $2,975,844 loan agreement with a commercial lender to provide financing for purchase of this rented equipment and to replace an existing loan the Company had with the lender.  This loan is repayable over a period of 48 months at a fixed per annum interest rate of 5.75% and is collateralized by the equipment.  In July 2008, the Company entered into a $3,200,000 loan agreement with a bank to provide financing for the purchase of seismic recording equipment.  This loan is repayable over 36 months at a fixed per annum interest rate of 6.00% and is collateralized by the equipment.  In August 2008, the Company entered into a $2,003,700 loan agreement with a bank to provide financing for the purchase of new vibration vehicles.  This loan is repayable over 36 months at a fixed per annum interest rate of 6.00% and is collateralized by the vibration vehicles.  In September 2008, the Company entered into a $2,690,402 loan agreement with a commercial lender to provide financing for our eighth new ARAM ARIES recording system. This loan is repayable over a period of 48 months at a fixed per annum interest rate of 6.00% and is collateralized by the recording system.  Also in September 2008, the Company entered into a $1,092,053 loan agreement with the same commercial lender to provide financing for recording equipment that goes with the eighth ARAM ARIES recording system.  This loan is co-terminus with the loan for the recording system, and carries a fixed per annum interest rate of 6.00% and is collateralized by the recording equipment.

In April of 2004, we executed an addendum to our lease of a facility in Plano, Texas, that included approximately 10,500 square feet of office and warehouse space and an outdoor storage area of approximately 20,000 square feet.  This facility was used to repair geophysical equipment and housed our corporate offices until September of 2006.  In September of 2005, we leased an additional facility, in Plano, Texas, with approximately 10,000 square feet of office and warehouse space and an additional 10,000 square feet of outdoor storage to accommodate our growth.  This facility was used primarily to repair geophysical equipment.  In January of 2006, we leased a 600 square foot facility in Houston, Texas, to be used as a sales office.  In July of 2006, we entered into a lease for 7,269 square feet of office space located in Plano, Texas.  In September of 2006, we relocated our corporate offices to this facility and in September 2008 increased the size of the lease to 8,523 square feet of office space.  In October of 2006, we leased an 800 square foot facility in Oklahoma City, Oklahoma, to be used as a sales office.  In September of 2007, we leased a 1,130 square foot facility in Denver, Colorado, to be used as a sales office. In September 2008, we leased a 400 square foot facility is Pratt, Kansas, to be used as a permit office.  In November 2008, we vacated our two Plano repair, warehouse and outdoor storage facilities, and moved to a leased repair, warehouse and outdoor storage facility in Denison, Texas.  The Denison, Texas, facility consists of one 5,000 square foot building, two 10,000 square foot adjacent buildings and an outdoor storage area of approximately 60,500 square feet.

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Contractual Obligations

The following table summarizes payments due in specific periods related to our contractual obligations as of December 31, 2008:

(1)          See “Capital Resources” above for a discussion of the contractual obligations we have incurred since December 31, 2008.

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 2009 capital expenditures through cash flow from operations, borrowings from commercial lenders, and the funds available under our line of credit loan agreement.  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, 2008, 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 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

Seismic Surveys

The Company provides seismic data acquisition survey services to its customers under general service agreements which define certain obligations for the Company and for its customers.  A supplemental agreement setting forth the terms of a specific project, which may be cancelled by either party upon 30 days advance written notice, is entered into for every project.  These supplemental agreements are either “turnkey” agreements providing for a fixed fee to be paid for each unit of seismic data acquired or “term” agreements providing for a fixed hourly, daily, or monthly fee during the term of the project.  The duration of these projects will vary from a few days to several months.  The Company recognizes revenue when services are performed under both types of agreements.  Services are defined as the commencement of data acquisition.  Under turnkey agreements, the total number of units of seismic data to be gathered is set forth in the agreement, and revenue is recognized as services are performed on a per unit of seismic data acquired rate.  Under term agreements, revenue is recognized as services are performed based on the time worked rate provided in the term agreement.  Under both turnkey and term agreements, cost of earned revenue is recognized by multiplying total estimated agreement cost by the percentage-of-completion of the agreement.  The excess of that amount over the cost of earned revenue reported in prior periods is recognized as cost of earned revenue for the period.  Agreements are not segmented nor combined for purposes of calculating percentage of completion.  The asset “Costs and estimated earnings in excess of billings on uncompleted contracts” represents cost incurred on turnkey agreements in excess of billings on those agreements.  The liability “Billings in excess of costs and estimated earnings on uncompleted contracts” represents billings on turnkey agreements in excess of cost on those agreements.  Claims have been negligible in the years ended December 31, 2008, 2007, and 2006.

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Gravity Data

The Company owns 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.  When an order for gravity data is received, the portion of gravity data requested by the customer is prepared in digital format for licensing and shipment to the customer.  This process is performed by an employee in the Company’s headquarters office and normally takes no longer than a few days.  The licensing of gravity data is not a material part of the Company’s revenue.  Gravity data revenue during the years ended December 31, 2008, 2007, and 2006 was approximately $46,100, $187,300, and $500, respectively.

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 are fundamental to assessing demand for our services. If we are unable to achieve these cash flows, our estimates will 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 estimate 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. In July of 2006, FIN 48, “Accounting for Uncertainty in Income Taxes — an interpretation of Financial Accounting Standards Board (FASB) Statement No. 109,” was issued.  FIN 48 prescribes a recognition threshold and measurement attribute for tax positions.  The Company adopted FIN 48 at the beginning of fiscal year 2007 which did not have a material impact on the financial statements.

Stock Based Compensation

Prior to January 1, 2006, the Company accounted for its stock options under the recognition and measurement principles of APB Opinion No. 25, and related interpretations.  Accordingly, no stock-based employee

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compensation cost was reflected in our financial statements prior to January 1, 2006 since all options to purchase common stock of the Company had an exercise price equal to, or greater than, the market value of the underlying common stock on the date of grant.

Effective January 1, 2006, the Company implemented Statement of Financial Accounting Standards (SFAS) No. 123R, “Share Based Payment (SFAS 123R),” for stock-based compensation awards granted after that date and for unvested awards outstanding at that date using the modified prospective application method.  We recognize the fair value of the stock-based compensation awards as wages in the Statements of Income on a straight-line basis over the vesting period.  Such implementation is expected to have minimal impact on our results of operations, financial position, and liquidity.  The adoption of SFAS 123R resulted in the recognition of compensation expense, relative to stock-based awards, in wages in the Statements of Income of approximately $455,000, or approximately $0.03 per share, for the year ended December 31, 2008 and $430,000, or approximately $.03 per share, for the year ended December 31, 2007.  In accordance with the modified prospective application method permitted by SFAS 123R, prior period amounts have not been restated to reflect the recognition of stock-based compensation costs.

In April of 2006, 106,391 shares of restricted stock were issued to employees of the Company under the Company’s 2006 Stock Award Plan (“2006 Stock Award Plan”).  In August 2007, 18,900 shares of restricted stock were issued to employees of the Company under the 2006 Stock Award Plan.  In June 2008, 10,000 shares of restricted stock were issued to an employee of the Company under the 2006 Stock Award Plan.  In October 2008, 335,000 stock options were issued to employees of the Company under the 2006 Stock Award Plan.  As of December 31, 2008, there was approximately $742,000 of unrecognized compensation expense related to our two-share based compensation plans.

Recently Issued Accounting Pronouncements

In September of 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes guidelines for measuring fair value, and expands disclosures regarding fair value measurements.  This statement applies when other accounting pronouncements require or permit assets or liabilities to be measured at fair value, but does not expand the use of fair value to new accounting transactions.  SFAS 157 is effective for fiscal years beginning after November 15, 2007, and for non-financial assets and liabilities, generally, in fiscal years beginning after November 15, 2008.  As of December 31, 2008, the Company has no financial assets and liabilities that are required to be measured at fair value.  SFAS 157 excluded stock-based compensation from its scope.  The Company primarily uses fair value to measure goodwill (non-financial asset), and its associated reporting unit, in connection with our annual impairment analysis.  SFAS 157, as it is currently written, will apply measurement and disclosure requirements in connection with our goodwill impairment analysis effective in the fiscal year beginning after November 15, 2008.  We expect that SFAS 157 will not have a significant effect on our goodwill impairment test, but it will require enhanced disclosures.

In September of 2006, SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of SFAS No. 87, 88, 106, and 132(R),” was issued SFAS No. 158 requires the funded status of pension and postretirement plans to be recorded as assets or liabilities and unrecognized gains or losses to be recorded as accumulated other comprehensive loss in the balance sheet.  The Company has no defined benefit pension or other postretirement plans.  As a result, SFAS No. 158 did not have an effect on the Company’s results.

In February of 2007, the FASB issued SFAS No. 159 (“SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities.”  SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value.  SFAS 159 is effective for fiscal years beginning after November 15, 2007.  The adoption of SFAS 159 has not had a significant effect on our financial statements.

In December of 2007, the FASB issued Statement of Financial Accounting Standards No. 141R, “Business Combinations,” (SFAS 141R) effective for fiscal years beginning after December 15, 2008.  Under SFAS 141R an acquiring entity in a business combination is required to recognize all assets acquired and liabilities assumed in the transaction.  The revised standard also establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed.  The rule requires an acquirer to disclose all of the information users may need to evaluate and understand the nature and financial effect of the business combination.  The Company is currently evaluating SFAS 141R and does not expect these new rules to have a material impact on the Company’s overall results of operations, financial position, or cash flows.

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In December of 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Non-controlling Interest in Consolidated Financial Statements – an amendment of ARB No. 51,” (SFAS 160) effective for fiscal years beginning after December 15, 2008.  SFAS 160 requires all entities to report non-controlling (minority) interest in subsidiaries as equity in the consolidated financial statements.  Its intention is to eliminate the diversity in practice regarding the accounting for transactions between an entity and non-controlling interest. The Company is currently evaluating SFAS 160 and does not expect these new rules to have a material impact on the Company’s overall results of operations, financial position or cash flows.

In May 2008, the FASB issued SFAS No. 162 (“SFAS 162”), “The Hierarchy of Generally Accepted Accounting Principles.”  Under SFAS 162, the GAAP hierarchy will now reside in the accounting literature established by the FASB.  SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP.  SFAS 162 is effective 60 days following the SEC’s approval of the Public Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Presented Fairly in Conformity with Generally Accepted Accounting Principles.”  We do not expect the adoption of SFAS 162 to have a material impact on our financial statements.

Effect of Inflation

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

Information Regarding Forward-Looking Statements

This Form 10-K includes “forward-looking statements” as defined in Section 27A of the Securities Act of 1933, as amended (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-K.

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES 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

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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 year ended December 31, 2008, our top two customers accounted for approximately 14.4% and 12.3% of our revenues.  For the year ended December 31, 2007, our top two customers accounted for approximately 12.1% and 9.9% of our revenues.  For the year ended December 31, 2006, no customer accounted for 10% or more of our revenues.

For further information see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Item 1A. Risk Factors.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Financial Statements

December 31, 2008, 2007, and 2006

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, 2008 and 2007, and the related statements of income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008.  These financial statements are the responsibility of the Company’s management.  We also have audited TGC Industries, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  TGC Industries, Inc.’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on these financial statements and an opinion on the company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TGC Industries, Inc. as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, TGC Industries, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the COSO.

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TGC Industries, Inc.

BALANCE SHEETS

December 31,

The accompanying notes are an integral part of these financial statements

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TGC Industries, Inc.

BALANCE SHEETS — Continued

December 31,

The accompanying notes are an integral part of these financial statements

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TGC Industries, Inc.

STATEMENTS OF INCOME

Years Ended December 31,

The accompanying notes are an integral part of these financial statements

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TGC Industries, Inc.

STATEMENTS OF SHAREHOLDERS’ EQUITY