GMX Resources (GMXRW) 10-K/A 2006 FY Annual report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2006

Commission file number 001-32977

GMX RESOURCES INC.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1534474
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
9400 North Broadway, Suite 600, Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip Code)
(Registrant’s telephone number, including area code)	(405) 600-0711

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

Title of Class	Name of Exchange on Which Registered
Common Stock, $0.001 par value	The NASDAQ Stock Market, LLC
Series B Cumulative Preferred Stock, $0.001 par value	The NASDAQ Stock Market, LLC

Securities registered under Section 12(g) of the Exchange Act: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

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. Yesþ Noo

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

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

Large accelerated filero      Accelerated filerþ      Non-accelerated fileo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yeso Noþ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked prices of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. As of June 30, 2006 aggregate market value was $272,118,201.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: As of March 9, 2007, there were 13,267,136 shares of Common Stock, par value $.001 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:Portions of the Company’s definitive proxy statement for our 2007 annual meeting of shareholders are incorporated into Part III of this Form 10-K by reference.

EXPLANATORY NOTE

We are filing this amendment (“Amended Report”) to our Annual Report for the year ended December 31, 2006 (“Report”) to reflect changes made in response to comments received by us from the Staff of the Securities and Exchange Commission (“SEC”) in connection with the Staff’s review of the Report. Our consolidated financial position and consolidated results of operations for the periods presented have not been restated from the consolidated financial position and consolidated results of operations originally reported. For convenience and ease of reference we are filing the Amended Report in its entirety with the applicable changes. Unless otherwise stated, all information contained in this Amended Report is as of the original filing date of our Report and has not been amended to reflect any subsequent events.

Pursuant to the rules of the SEC, currently dated certifications from our Chief Executive Officer and Chief Financial Officers required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 are filed herewith. The following sets forth the changes made to the Report by this amendment:

1. The Company’s Commission File Number was amended to correct a typographical error.

2. The address of the SEC under the heading “Availability of Information,” on page 11 was corrected.

3. The statements of cash flows on page F-8 were amended to eliminate the line item “Net cash provided by operating activities before working capital changes.”

4. Footnote A of the Financial Statements under the subheading “Property and Equipment” has been revised to more fully describe the full cost method of accounting that we use in conformity with SEC regulations.

5. Footnote A of the Financial Statements under the heading “Revenue Recognition and Natural Gas Balancing” has been revised to more accurately reflect when production is considered to be sold for purposes of revenue recognition.

6. Footnote B of the Financial Statements has been revised to reflect total acquisition costs not subject to amortization by year. In addition the amount of capital cost of unproved properties excluded from amortization has been shown separately on the face of the balance sheet.

7. Footnote N of the Financial Statement footnotes has been amended to correct a typographical error in the date of our common stock offering.

8. Exhibits 31.1 and 31.2 have been revised to eliminate the title of the certifying individual at the beginning of the certification.

9. The heading of the risk factor relating to estimation of reserves and future net cash flows on page 16 has been revised.

10. Exhibits 23.2 and 23.3 have been added to include consents of independent engineers. A new accountant’s consent has been included as Exhibit 23.1.

11. Footnote L to the Financial Statements has been amended to add disclosure for the reasons for increases in reserve quantities from extensions, discoveries and other additions.

The Staff also issued comments regarding the quantity of proved reserves we reported at December 31, 2006, primarily the quantities of proved undeveloped reserves reported. To a lesser extent the comments relate to quantities of proved developed non-producing reserves associated with two wells that had been drilled but not fully completed at year end (but which were subsequently successfully completed). We have responded to the Staff comments stating our position that we believe our 2006 reserve estimates were correct in all material respects and are awaiting further communication from the Staff. If the Staff continues to disagree with our position, and we are unable to subsequently satisfactorily resolve the Staff’s concerns, we may be required to amend the Report again to lower the amount of reserves reported, which would in turn possibly require a restatement of our financial statements for the year then ended, as well as quarterly financial statements for the first three quarters of 2007, to reflect depletion at a higher rate than has been previously reported, which would in turn reduce our previously reported net income and net income per share. Any reduction in reserves would also reduce the previously reported Present Value of the reserves and the standardized measure of discounted future cash flows. Any such restatement would not affect previously reported cash flow from operating activities. We do not anticipate that any change in reported reserve quantities would require any writedown of the value of oil and gas properties on our 2006 year end balance sheet. The exact quantity of any reserve quantity adjustment that may be ultimately required, if any, is not yet certain but it could be a reduction in total reserves as of year end 2006 of approximately 37.8 Bcfe, from the 258.4 Bcfe previously reported to 220.6 Bcfe (a decrease of 14.6%), of which 29.9 Bcfe would be a reduction in proved undeveloped reserves and 7.9 Bcfe would be a reduction in proved developed reserves. The potential after tax financial effect from this reserve reduction would be an increase of depreciation, depletion and amortization expense (and a decrease in net income) of $280,000 or $0.02 per diluted common share (a decrease of 3%) for the year ended December 31, 2006 and $1.2 million or $0.09 per diluted common share (a decrease of 14%) for the nine months ended September 30, 2007. We do not anticipate that any of the SEC Staff comments will affect our year end 2007 proved reserve estimate of 437 Bcfe because we believe the 2007 reserve estimates have been prepared on a basis consistent with the Staff’s comments. However, until the Staff’s position is more certain, there is a risk that our 2006 and 2007 reserve estimates may require further adjustments.

GMX RESOURCES INC.
Form 10-K
Table of Contents

	Page
PART I		1
Item 1. Business		1
General		1
2006 and 2007 Developments		2
Business Strategy		2
2007 Plans		3
Marketing		3
Regulation		4
Gas Gathering		7
Competition		7
Facilities		8
Employees		8
Certain Technical Terms		8
Availability of Information		11
Item 1A. Risk Factors		12
Risks Related to GMX		12
Risks Related to the Oil and Gas Industry		15
Item 1B. Unresolved Staff Comments		19
Item 2. Properties		19
General		19
East Texas		20
Northwestern Louisiana		22
Southeast New Mexico		23
Reserves		23
Costs Incurred		24
Drilling Results		25
Acreage		26
Productive Well Summary		26
Item 3. Legal Proceedings		26
Item 4. Submission of Matters to a Vote of Security Holders		26
PART II		27
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		27
Common Stock		27
Equity Compensation Plan Information		27
Shareholder Return Performance Graph		28
Recent Sales of Unregistered Securities		28

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Purchases of Equity Securities	28
Item 6. Selected Financial Data	28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation	30
Summary Operating and Reserve Data	30
Critical Accounting Policies	31
Results of Operations for the Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005	34
Results of Operations for the Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004	35
Capital Resources and Liquidity	36
Credit Facility	37
Other Financing – 2006 and 2007	38
Working Capital	38
Commitments and Capital Expenditures	38
Liquidity and Financing Considerations	39
2007 Guidance	39
Recently Issued Accounting Pronouncements	39
Off-Balance Sheet Arrangements	39
Price Risk Management	39
Forward-Looking Statements	40
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	40
Item 8. Financial Statements and Supplementary Data	41
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	41
Item 9A. Controls and Procedures	41
Controls and Procedures	41
Changes in Internal Control Over Financial Reporting	42
Management’s Annual Report on Internal Control over Financial Reporting	42
Certifications	42
Item 9B. Other Information	42
PART III	43
PART IV	44
Item 15. Exhibits and Financial Statement Schedules	44
Exhibit 23.1
Exhibit 23.2
Exhibit 23.3
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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PART I

Item 1. Business

General

GMX Resources Inc. (referred to herein as “we,” “us,” “GMX” or the “Company”) is an independent oil and gas company engaged in the development and exploitation of natural gas and oil properties. Our drilling, development and production activities are primarily focused on the Cotton Valley Sands in the Carthage, North Field of Harrison and Panola counties of East Texas. In addition to our wholly-owned properties in the Carthage, North Field, we are a party to a joint development agreement with Penn Virginia Oil & Gas, L.P. (“PVOG”), a wholly-owned subsidiary of Penn Virginia Corporation (NYSE: PVA). As of December 31, 2006, we owned 164 gross (95.8 net) producing wells; of these, 119 gross (56.3 net) Cotton Valley wells are located in the Carthage, North Field. We also hold a large inventory of Cotton Valley Sand development prospects, including 29,004 gross (15,789 net) acres which includes net proceeds lease of 641 acres. We have remaining 597 gross and 362.7 net Cotton Valley locations based on 40 acre well spacing. We believe the Cotton Valley Formation in this area is composed of eight gas saturated layers ranging from 8,000 to 12,000 feet deep. The Upper Cotton Valley Sands encompasses the Stroud, BCD, Davis and Taylor layers and the Lower Cotton Valley layers encompass the Upper, Middle and Lower Bossier shale as well as the Haynesville Lime, and below the Cotton Valley is the Smackover Lime. As of March 12, 2007, we recently completed our first two horizontal wells in the Upper Cotton Valley Sands and had one additional horizontal well to complete. Depending on the success of these wells, we may drill additional horizontal wells in 2007. We recently received a final order amending the field rules for the Carthage, North (Cotton Valley) Field, Harrison and Panola counties, Texas that permits 20 acre spacing. We are also involved in the drilling and development of wells in the Tatum Basin in Southeast New Mexico, where we had interests in 9 gross (5.6 net) producing natural gas wells as of December 31, 2006.

Our strategy is to continue to build shareholder value by aggressively developing our East Texas natural gas properties, using multiple rigs to drill our undeveloped acreage in order to increase production and expand our proved and unproved natural gas reserves, while maintaining what we believe to be a strong balance sheet and financial position. We will continue to evaluate strategic alternatives to enhance growth and value for our shareholders.

Our principal executive office is located at 9400 North Broadway, Suite 600, Oklahoma City, Oklahoma, 73114 and our telephone number is (405) 600-0711.

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2006 and 2007 Developments

Our focus in 2006 was, and in 2007 will be, the continued drilling and development of our interests in the Carthage, North Field. During 2006, PVOG drilled and completed a total of 46 gross wells, 16 wells net to GMX. Of these 46 gross wells, 35 gross and 10.5 net were drilled and completed in the JV 30% and 11 gross and 5.5 net were drilled and completed in JV 50% Areas. In the GMXR 100% Area, we drilled 19 wells (17 Cotton Valley and 2 Travis Peak) and completed 15 (13 Cotton Valley and 2 Travis Peak) before year-end. The remaining 4 wells drilled in 2006 were completed in early 2007. We and PVOG increased the number of rigs we were using in the Carthage, North Field to seven at year end. We constructed and put in use one drilling rig and partially constructed our third rig in 2006. We use these rigs to drill in our GMXR 100% area. Our capital expenditures in 2006 were $130.6 million, of which $26.2 million was expended on rigs, equipment and gathering systems and the balance on drilling and completion of wells, acreage acquisitions, recompletions, and costs incurred for wells to be drilled in 2007. The average Cotton Valley vertical well costs for 2006 was approximately $1.85 million. For more details on our joint development agreement with PVOG, see “Item 2. Properties – East Texas.”

In 2006, we funded our drilling and development activity in our East Texas properties with proceeds of approximately $14 million from the exercise of warrants, proceeds of a $50 million preferred stock offering in August 2006, proceeds from borrowings on our line of credit, and cash flow from operations.

In February 2007, we completed a public offering of 2,000,000 shares of our common stock at a price of $34.82 per share. We intend to use the net proceeds from this offering of approximately $65.5 million to fund drilling and development of our East Texas properties and for other general corporate purposes. Pending such uses, a portion of the net proceeds from this offering will be used to reduce indebtedness under our revolving bank credit facility, which will permit additional borrowings in the future under the terms of our bank credit facility.

Business Strategy

Our strategy is to create additional value from our East Texas property base through development of quality proved undeveloped properties and exploitation activities focused on adding proved reserves from the inventory of probable and possible drilling locations. We have the following resources:

Experienced Management.The Company’s founders have experience in finding, exploiting, developing and operating reserves and companies. Ken L. Kenworthy, Jr., the Company’s President, has been active in various aspects of the oil and gas business for over 30 years. He was formerly Chairman and Chief Executive Officer of OEXCO, Inc. (“OEXCO”), an Oklahoma City based privately held oil and gas company. He founded OEXCO in 1980 and successfully managed it until 1995 when it was sold for approximately $13 million. During this 15-year period, OEXCO operated approximately 300 wells. Ken L. Kenworthy, Sr. also has extensive financial experience with private and public businesses, including experience as Chief Financial Officer of CMI Corporation, formerly a New York Stock Exchange listed company that manufactured and sold road-building equipment.

Substantial Drilling and Exploitation Opportunities.In East Texas, we have a substantial inventory of drilling projects with an estimated 176 Bcfe Cotton Valley and 5 Bcfe other of proved undeveloped reserves as of December 31, 2006. These projects include 264 Cotton Valley and 9 other new drilling locations (net 160 Cotton Valley) with proved undeveloped reserves. We expect to locate additional proved drilling and recompletion opportunities as our evaluation and drilling of the property base continues. Based on our December 31, 2006 reserve report, the pre-tax present value of the proved reserves is $262 million with anticipated future development costs of $310 million.

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Significant Inventory of Unproved Prospects.We have approximately 333 gross/203 net additional drilling locations in East Texas which we believe have potential in the Cotton Valley Formation at depths of 8,000 to 12,000 feet. More than 21,410 acres of our 29,004 gross acres of Cotton Valley leasehold rights are held by production.

Emphasis on Gas Reserves.Production for 2006 was 90% gas and 10% oil. Proved reserves as of December 31, 2006 are 94% gas and 6% oil. We intend to emphasize development of gas reserves due to the long term outlook for gas demand, but will continue to maintain a portion of our reserves in oil.

Joint Development of East Texas. Our participation agreement with PVOG enables us to participate in the development of our East Texas property at a faster pace than we could fund independently. By having an industry partner with greater financial and other resources, we are able to accelerate the drilling and development of this property base while still participating at meaningful ownership levels. During 2006, we and PVOG acquired rights to use additional rigs to accelerate development and we expect further acceleration in 2007. We consider that our relationship with PVOG is good.

Control of Rigs.We currently control the use of two rigs which are owned by Diamond Blue Drilling Co. (“DBD”), a subsidiary wholly-owned by us. In 2005, DBD purchased a 11,000-foot depth drilling rig we previously had under contract, and in the second quarter of 2006, DBD acquired an additional 14,000-foot depth rig. These rigs will be used to drill in the GMXR 100% Area and enable us to guarantee rig availability and drill at reduced costs. We have a third rig under construction with an expected delivery date during the second quarter of 2007.

2007 Plans

By the end of 2007, we and PVOG expect to have up to 8 drilling rigs in operation in East Texas, including the 3 rigs owned by us. Current plans include drilling of up to 86 gross/35.6 net wells in the JV 30% and JV 50% Areas and up to 33 wells in the GMXR 100% Area. Our share of the capital expenditures for these wells is estimated to be in a range of approximately $145 million to $175 million. Completion of these plans will depend on drilling results, rig availability and other factors. See “ Item 2. Properties.”

Marketing

Our ability to market oil and gas often depends on factors beyond our control. The potential effects of governmental regulation and market factors, including alternative domestic and imported energy sources, available pipeline capacity, and general market conditions are not entirely predictable.

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Natural Gas.Natural gas is generally sold pursuant to individually negotiated gas purchase contracts, which vary in length from spot market sales of a single day to term agreements that may extend several years. Customers who purchase natural gas include marketing affiliates of the major pipeline companies, natural gas marketing companies, and a variety of commercial and public authorities, industrial, and institutional end-users who ultimately consume the gas. Gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market may vary daily, reflecting changing market conditions. The deliverability and price of natural gas are subject to both governmental regulation and supply and demand forces.

Substantially all of our gas from our East Texas company-operated wells is initially sold to our wholly owned subsidiary, Endeavor Pipeline Inc. (“Endeavor”), which in turn sells gas to unrelated third parties. All of our gas is currently sold under contracts providing for market sensitive terms which are terminable with 30-60 day notice by either party without penalty. This means that we enjoy both the high prices in increasing price markets and suffer low prices when gas prices decline. In addition, PVOG markets 100% of the gas produced from wells operated by PVOG in the JV 30% and 50% Areas and we market the gas in the 100% Area of our joint development under the terms of month-to-month contracts on the spot market at a price with market sensitive terms. A subsidiary of PVOG charges us a marketing fee of 1% of the sales proceeds subject to certain price caps for oil and gas sold on our behalf in the JV 30% and 50% Areas.

Crude Oil.Oil produced from our properties will be sold at the prevailing field price to one or more of a number of unaffiliated purchasers in the area. Generally, purchase contracts for the sale of oil are cancelable on 30-days notice. The price paid by these purchasers is an established market or “posted” price that is offered to all producers.

We do not currently have any long-term contracts to sell natural gas or crude oil. None of our gas or oil sales contracts have a term of more than one year.

In 2006, our largest purchasers were various purchases through PVOG, Crosstex Pipeline Company and TEPPCO Crude, which accounted for 48%, 36% and 7% of total oil and natural gas sales. We do not believe that the loss of any of our purchasers would have a material adverse affect on our operations as there are other purchasers active in the market.

Regulation

Exploration and Production.The exploration, production and sale of oil and gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. All of these regulations may adversely affect the rate at which wells produce oil and gas and the number of wells we may drill. All statements in this report about the number of locations or wells reflect current laws and regulations.

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Laws and regulations relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.

Environmental Matters.The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to the liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

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There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Marketing and Transportation.Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”) that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. We cannot predict what further action the FERC will take on these matters. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

Additional proposals and proceedings that might affect the natural gas industry are frequently made before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

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Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.

Gas Gathering

We have acquired, constructed and own, through a wholly owned subsidiary, Endeavor Pipeline, Inc., gas gathering lines and compression equipment for gathering and delivering of natural gas from our East Texas properties that we operate. As of December 31, 2006, this gathering system consisted of approximately 95 miles of gathering lines and 9 compressors that collect and compress gas from approximately 100% of our gas production from company-operated wells in 2006. In 2007, we expect to add approximately 15 miles of pipeline and additional compressors. This system enables us to improve the control over our production and enhances our ability to obtain access to pipelines for ultimate sale of our gas. We only gather gas from wells in which we own an interest. Remaining gas is gathered by unrelated third parties. Endeavor also serves as first purchaser of gas from wells for which we are the operator. See “Item 1. Business-Marketing.”

PVOG has installed and operates gathering facilities to each of the wells drilled and operated by PVOG in the JV 30% and 50% Areas. PVOG charges us a gathering fee of $0.10/MMBtu and actual cost of compression plus five percent (5%) for all gas gathered at the wellhead and redelivered to a central sales point. A subsidiary of PVOG charges us a marketing fee of 1% of the proceeds from oil and gas sales subject to certain price caps.

Competition

We compete with major integrated oil and gas companies and independent oil and gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

Recent increased oil and gas drilling activity in East Texas has resulted in increased demand for drilling rigs and other oilfield equipment and services. We have and may continue to experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and gas leases to lapse.

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Facilities

As of December 31, 2006, we leased 9,532 square feet in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental cost is approximately $147,000. We also lease 3,200 square feet of office space in Marshall, Texas used primarily for land field operations. The annual rent is approximately $24,000.

In addition, we own a 50-acre operations field yard approximately seven miles southeast of Marshall, Texas that has 10,800 square feet of office and warehouse space.

Employees

As of December 31, 2006, we had 99 full-time employees. This compares to sixteen full-time employees at December 31, 2005, reflecting the increase in our activities in 2006, including 63 employees of DBD. We also use a number of independent contractors to assist in land and field operations. We expect to add additional personnel in 2007 as our activities continue to increase. We believe our relations with our employees are satisfactory. Our employees are not covered by a collective bargaining agreement.

Certain Technical Terms

The terms whose meanings are explained in this section are used throughout this document:

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

Bcf.Billion cubic feet.

Bcfe.Billion cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

Btu.British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

BBtu.Billion Btus.

Developed Acreage.The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Location.A location on which a development well can be drilled.

Development Well.A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.

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Drilling Unit.An area specified by governmental regulations or orders or by voluntary agreement for the drilling of a well to a specified formation or formations which may combine several smaller tracts or subdivides a large tract, and within which there is usually some right to share in production or expense by agreement or by operation of law.

Dry Hole.A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Estimated Future Net Revenues.Estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development costs, and future abandonment costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to deprecation, depletion and amortization.

Exploratory Well.A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Gross Acre.An acre in which a working interest is owned.

Gross Well.A well in which a working interest is owned.

Infill Drilling.Drilling for the development and production of proved undeveloped reserves that lie within an area bounded by producing wells.

Injection Well.A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field or productive horizons.

Lease Operating Expense.All direct costs associated with and necessary to operate a producing property.

MBbls.Thousand barrels.

MBtu.Thousand Btus.

Mcf.Thousand cubic feet.

Mcfpd. Thousand cubic feet per day.

Mcfe.Thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

MMBbls.Million barrels.

MMBtu.Million Btus.

MMcf.Million cubic feet.

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MMcfe.Million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

Natural Gas Liquids.Liquid hydrocarbons which have been extracted from natural gas (e.g., ethane, propane, butane and natural gasoline).

Net Acres or Net Wells.The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX.New York Mercantile Exchange.

Operator.The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease, usually pursuant to the terms of a joint operating agreement among the various parties owning the working interest in the well.

Present Value.When used with respect to oil and gas reserves, present value means the Estimated Future Net Revenues discounted using an annual discount rate of 10%.

Productive Well.A well that is producing oil or gas or that is capable of production.

Proved Developed Reserves.Proved reserves are expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by pilot project or after the operation of an installed program as confirmed through production response that increased recovery will be achieved.

Proved Reserves.The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved Undeveloped Reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances can estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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Recompletion.The completion for production of an existing wellbore in another formation from that in which the well has previously been completed.

Royalty.An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale), but generally does not require the owners to pay any portion of the costs of drilling or operating wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of a leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with the transfer to a subsequent owner.

Secondary Recovery.An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and water flooding are examples of this technique.

Undeveloped Acreage.Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Waterflood.A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working Interest.An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

Workover.To carry out remedial operations on a productive well with the intention of restoring or increasing production.

Availability of Information

We file periodic reports and proxy statements with the Securities and Exchange Commission (“SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of this site is http://www.sec.gov.

Our internet address is www.gmxresources.com. We make available on our website free of charge copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably possible after we electronically file such material with, or furnish such it to, the SEC.

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Item 1A. Risk Factors.

Risks Related to GMX

Our principal shareholders own a significant amount of common stock, giving them significant influence over corporate transactions and other matters.

As of March 1, 2007, Ken L. Kenworthy, Jr. (and his wife) and Ken L. Kenworthy, Sr. beneficially own approximately 11.4% and 6.6% respectively, of our outstanding common stock. These shareholders, acting together, have a significant influence on the outcome of shareholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. This concentrated ownership may make it more difficult for any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors may also delay or prevent a change in the management or voting control of GMX.

The loss of our President or other key personnel could adversely affect us.

We depend to a large extent on the efforts and continued employment of Ken L. Kenworthy, Jr., our President, and Ken L. Kenworthy, Sr., our Executive Vice President. The loss of the services of either of them could adversely affect our business. In addition, it is a default under our credit agreement if there is a significant change in management or ownership.

We are managed by the members of a single family, giving them influence and control in corporate transactions and their interests may differ from those of other shareholders.

Our executive officers consist of Ken L. Kenworthy, Jr., and his father. Because of the family relationship among members of management, certain employer/employee relationships, including performance evaluations and compensation reviews may not be conducted on a fully arms-length basis as would be the case if the family relationships did not exist. Our board of directors include members unrelated to the Kenworthy family and we expect that significant compensation and other relationship issues between GMX and its management will be reviewed and approved by an appropriate committee of outside directors. However, as the owners of a significant percentage of our common stock, the Kenworthys have significant influence over the current directors.

Our wells produce oil and gas at a relatively slow rate.

We expect that our existing wells and other wells that we plan to drill on our existing properties will produce the oil and gas constituting the reserves associated with those wells over a period of between 15 and 70 years at relatively low annual rates of production. By contrast, wells located in other areas of the United States, such as offshore Gulf coast wells, may produce all of their reserves in a shorter period, for example, four to seven years. Because of the relatively slow rates of production of our wells, our reserves will be affected by long term changes in oil or gas prices or both and we will be limited in our ability to anticipate any price declines by increasing rates of production. We may hedge our reserve position by selling oil and gas forward for limited periods of time but we do not anticipate that, in declining markets, the price of any such forward sales will be attractive.

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Our future performance depends upon our ability to obtain capital to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations. The business of exploring for, developing or acquiring reserves is capital intensive. Our ability to make the necessary capital investment to maintain or expand our oil and natural gas reserves is limited by our relatively small size. Further, our East Texas joint development partner, PVOG, may propose drilling that would require more capital than we have available from cash flow from operations or our bank credit facility. In such case, we would be required to seek additional sources of financing or limit our participation in the additional drilling. In addition, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil or gas reserves will be encountered.

We have not paid dividends and do not anticipate paying any dividends on our common stock in the foreseeable future.

We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. We do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends on our common stock will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs and other factors. The declaration and payment of any future dividends on our common stock is currently prohibited by our credit agreement and may be similarly restricted in the future.

Hedging our production may result in losses or limit potential gains.

We enter into hedging arrangements to limit our risk to decreases in commodity prices or if required by our bank credit facility. Hedging arrangements expose us to risk of financial loss in some circumstances, including the following:

• production is less than expected;

• the counter-party to the hedging contract defaults on its contact obligations; or

• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who may or may not engage in hedging arrangements.

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Our credit facility contains certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our credit facility includes certain covenants that, among other things, restrict:

• our investments, loans and advances and the paying of dividends on common stock and other restricted payments;

• our incurrence of additional indebtedness;

• the granting of liens, other than liens created pursuant to the credit facility and certain permitted liens;

• mergers, consolidations and sales of all or substantial part of our business or properties; and

• the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities.

Our credit facility requires us to maintain certain financial ratios, such as leverage ratios. All of these restrictive covenants may restrict our ability to expend or pursue our business strategies. Our ability to comply with these and other provisions of our credit facility may be impacted by changes in economic or business conditions, results of operations or events beyond our control. The breach of any of these covenants could result in a default under our credit facility, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Failure by us to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could have a material adverse effect on our business and stock price.

We have evaluated our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We have performed the system and process evaluation and testing required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. As of December 31, 2006, we were required to comply with Section 404. Upon completion of this process, we did not identify control deficiencies under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we are required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonable likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim consolidated financial statements will not be prevented or detected. Failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our consolidated financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our consolidated financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may be adversely affected.

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We have a shareholder rights plan and provisions in our organizational documents and under Oklahoma law that could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

We are an Oklahoma corporation. The existence of some provisions in our organizational documents and under Oklahoma law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our amended and restated certificate of incorporation and by-laws that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock and advance notice provisions for director nominations or business to be considered at a shareholder meeting. In addition, we have adopted a shareholder rights plan which is intended to deter third parties from making acquisitions of more than 20% of our stock without the approval of our Board of Directors.

Risks Related to the Oil and Gas Industry

A substantial decrease in oil and natural gas prices would have a material impact on us.

Oil and gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow. Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow under our credit facility is subject to periodic redeterminations based on prices specified by our bank at the time of determination. In addition, we may have full-cost ceiling test write-downs in the future if prices fall significantly.

Historically, the markets for oil and gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:

• worldwide and domestic supplies of oil and gas;

• weather conditions;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the availability of pipeline capacity;

• the price and level of foreign imports;

• domestic and foreign governmental regulations and taxes;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• political instability or armed conflict in oil-producing regions, and

• the overall economic environment.

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These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Because approximately 94% of our reserves at December 31, 2006 are natural gas reserves, we are more affected by movements in natural gas prices.

We have encountered difficulty in obtaining equipment and services.

Higher oil and gas prices and increased oil and gas drilling activity, such as those we experienced in 2006, generally stimulate increased demand and result in increased prices and unavailability for drilling rigs, crews, associated supplies, equipment and services. While we and PVOG have recently been successful in acquiring or contracting for services, we could experience difficulty obtaining drilling rigs, crews, associated supplies, equipment and services in the future. These shortages could also result in increased costs, delays in timing of anticipated development or cause interests in oil and gas leases to lapse. We cannot be certain that we will be able to implement our drilling plans or at costs that will be as estimated or acceptable to us.

Estimates of proved natural gas and oil reserves and present value of proved reserves are not precise.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. The reserve data included in this report represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, the precision of the engineering and geological interpretation, and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from our estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment. A reduction in oil and gas prices not only would reduce the value of any proved reserves, but also might reduce the amount of oil and gas that could be economically produced, thereby reducing the quantity of reserves. Our reserves and future cash flows may be subject to revisions, based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs, and other factors. Downward revisions of our reserves could have an adverse affect on our financial condition and operating results.

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At December 31, 2006, approximately 70% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures of $310 million to develop these reserves, including $145 million in 2007. However, these estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.

We may incur write-downs of the net book values of our oil and gas properties that would adversely affect our shareholders’ equity and earnings.

The full cost method of accounting, which we follow, requires that we periodically compare the net book value of our oil and gas properties, less related deferred income taxes, to a calculated “ceiling.” The ceiling is the estimated after-tax present value of the future net revenues from proved reserves using a 10% annual discount rate and using constant prices and costs. Any excess of net book value of oil and gas properties is written off as an expense and may not be reversed in subsequent periods even though higher oil and gas prices may have increased the ceiling in these future periods. A write-off constitutes a charge to earnings and reduces shareholders’ equity, but does not impact our cash flows from operating activities. Future write-offs may occur which would have a material adverse effect on our net income in the period taken, but would not affect our cash flows. Even though such write-offs do not affect cash flow, they can be expected to have an adverse effect on the price of our publicly traded securities.

Operational risks in our business are numerous and could materially impact us.

Our operations involve operational risks and uncertainties associated with drilling for, and production and transportation of, oil and natural gas, all of which can affect our operating results. Our operations may be materially curtailed, delayed or canceled as a result of numerous factors, including:

• the presence of unanticipated pressure or irregularities in formations;

• accidents;

• title problems;

• weather conditions;

• compliance with governmental requirements;

• shortages or delays in the delivery of equipment;

• injury or loss of life;

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• severe damage to or destruction of property, natural resources and equipment;

• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties; and

• other losses resulting in suspension of our operations.

In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above with a general liability and commercial umbrella policy with an aggregate limit of $7 million. We do not maintain insurance for damages arising out of exposure to radioactive material. Even in the case of risks against which we are insured, our policies are subject to limitations and exceptions that could cause us to be unprotected against some or all of the risk. The occurrence of an uninsured loss could have a material adverse effect on our financial condition or results of operations.

Governmental regulations could adversely affect our business.

Our business is subject to certain federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. These laws and regulations have increased the costs of our operations. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production could limit the total number of wells drilled or the allowable production from successful wells which could limit our revenues.

Laws and regulations relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.

Environmental liabilities could adversely affect our business.

In the event of a release of oil, gas or other pollutants from our operations into the environment, we could incur liability for personal injuries, property damage, cleanup costs and governmental fines. We could potentially discharge these materials into the environment in any of the following ways:

• from a well or drilling equipment at a drill site;

• leakage from gathering systems, pipelines, transportation facilities and storage tanks;

• damage to oil and natural gas wells resulting from accidents during normal operations; and

• blowouts, cratering and explosions.

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In addition, because we may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Competition in the oil and gas industry is intense, and we are smaller than many of our competitors.

We compete with major integrated oil and gas companies and independent oil and gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

General

As of December 31, 2006, we owned properties in the following productive fields and basins in the United States:

• East Texas, Carthage, North Field and Northwest Louisiana and East Texas, Waskom Field;

• The Tatum Basin, Crossroads Field in Southeast New Mexico.

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The following table sets forth certain information regarding our activities in each of these areas as of December 31, 2006.

	East Texas			Southeast
	and			New
Property Statistics:	Louisiana			Mexico			Total
Proved reserves (MMcfe)		256,311			2,092			258,403
Percent of total proved reserves		99	%		1	%		100	%
Gross producing wells		155			9			164
Net producing wells		90.1			5.7			95.8
Gross acreage		31,737			1,920			33,657
Net acreage		17,786			1,458			19,244
Proved developed reserves (MMcfe)		75,181			1,302			76,483
Proved undeveloped reserves (MMcfe)		181,130			790			181,920
Estimated total future development costs ($000s)		308,951			956			309,907
Estimated 2007 development costs ($000s)		145,000			0			145,000
Proved undeveloped locations		274			1			275
Year ended December 31, 2006 results:
Production (net MMcfe)		4,166			161			4,327
Average net daily production (Mcfe)		11,413			442			11,855

Additional information related to our oil and gas activities is included in Notes K and L to the financial statements beginning on Page F-1.

East Texas

The East Texas properties are located in Harrison and Panola Counties, Texas. These properties contain approximately 31,137 gross (17,417 net) acres with rights covering the Travis Peak, Pettit, Glen Rose and Cotton Valley formations. Our East Texas properties have 256.1 Bcfe of proved reserves or 99% of our total proved reserves at December 31, 2006, of which 181.1 Bcfe is classified as proved undeveloped.

We have interests in 150 gross (87.5 net) producing wells in East Texas, of which we operate 62, as of December 31, 2006. Average daily production net to our interest for 2006 was 10,326 Mcf of gas and 162 Bbls of oil. Production is primarily from Carthage North, Bethany, Blocker and Waskom Fields. The producing lives of these fields are generally 12 to 70 years. We have identified productive zones in the existing wells that are currently behind pipe and thus are not currently producing. These zones can be brought into production as existing reserves are depleted. Gas sold from the area has a high MMBtu content which can result in a net price above NYMEX average daily Henry Hub natural gas price. Oil is sold separately at a slight premium to the average NYMEX Sweet Crude Cushing price, inclusive of deductions. Most of the planned development will be added to existing gathering systems under comparable pricing and contracts.

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The acreage in East Texas lies on the Sabine Uplift, a broad positive feature which acts as a structural trap for most reservoirs. Most of the reservoirs are shallow and deep marine sediments which tend to have tremendous aerial extent and substantial thicknesses. Natural gas and oil production has been produced from 3,000 feet to 11,700 feet in our area. We have drilled or participated in over 100 wells in our development and 100% of the wells were productive. The primary objective of our development is the Cotton Valley Sand, which occurs between 8,200 feet and 10,000 feet and contains multiple layers of sands containing natural gas. Due to the multiple layers and widespread deposition of these gas saturated layers, we have a very high success rate of finding commercial wells.

In December, 2003, we entered into a participation agreement with PVOG for the joint development of our Cotton Valley, Travis Peak and Pettit prospects located in East Texas. The agreement was amended on several occasions in 2004, 2005 and 2006. The participation agreement expires in December 2007, although all rights under existing operating agreements continue after termination. This agreement, as amended, designates agreed geographic areas which surround and encompass distinct portions of our acreage positions in East Texas defined as “Phases.” PVOG began drilling in February 2004 in Phase I (the “JV 30% Area”), which includes, as of December 31, 2006, approximately 11,083 gross (3,325 net to GMX) acres. GMX had a 20% carried interest in the first five wells drilled in the JV 30% Area and were carried for 20% plus a 10% participation in two additional wells. PVOG has drilled and completed 71 wells in the JV 30% Area through December 31, 2006. Phase II (the “JV 50% Area”) includes approximately 7,680 gross (3,840 net) acres. We had a 20% carried interest in the first two wells and participated in an additional 10% and the right to participate for up to 50% of additional drilling in the JV 50% Area. PVOG has drilled and completed 14 wells in this area through December 31, 2006. At inception, we received 20% free participation in nine wells and approximately $950,000 in acreage and drilling location cost reimbursement which was applied to reduce current liabilities. The PVOG agreement also designates areas of mutual interest (“AMIs”) in which GMX and PVOG agree that they will have rights to jointly acquire acreage until December 2007. The JV 30% Area AMI consist of 20,500 gross acres in which GMX and PVOG have agreed to share future acreage acquisitions on a 70% PVOG/30% GMX basis. The JV 50% Area AMI consists of 22,400 gross acres and we have agreed to acreage acquisitions on a 50% PVOG/50% GMX sharing ratio. The Phase III (the “GMXR 100% Area”) AMI consists of 15,360 gross acres and is an area surrounding GMX’s existing wells. GMX has granted to PVOG a right of first refusal on any sale of acreage in the GMXR 100% Area and PVOG is restricted from acquiring acreage in the GMXR 100% Area until one year after termination of the participation agreement, unless GMX no longer owns acreage in the GMXR 100% Area. In 2006, we jointly acquired 1,185 gross acres in the JV 30% Area and 1,990 acres in the JV 50% Area. During 2006 we acquired 608 gross acres (1,224 net) in the GMXR 100% Area. Also, during 2006 we drilled 19 and completed 15 wells in the GMXR 100% Area.

The participation agreement originally limited PVOG to the use of one rig. During a portion of 2004, PVOG used two rigs under an amendment to our agreement whereby PVOG agreed to purchase a dollar denominated production payment from us to finance our share of costs of drilling using the second rig. This arrangement was terminated in November 2004 and since that date, only one rig was used throughout the remainder of 2004 and early 2005. We received approximately $2.8 million in funding from PVOG under this arrangement, which is repayable from 75% of our share of production proceeds from the wells financed. In March 2005, we entered into a further amendment to the joint participation agreement permitting PVOG to use two rigs, when one can be located, which permits us to share in the use of the second rig for our own account in drilling in Phase III, on an alternating basis with PVOG. We and PVOG each have the right to use the second rig for up to three consecutive wells. We will pay for the rig when we use it on the same terms as PVOG. Effective January 1, 2006, we agreed that PVOG could use two additional rigs. Either party may terminate the multiple rig provisions on 60 days notice subject to the terms of any drilling contract for the second rig.

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Our success rate has been 100% on wells drilled and completed in 2005 and 2006. There is a remaining potential for up to 597 gross (363 net) locations of Cotton Valley wells in our East Texas acreage assuming an ultimate well density of one well in each 40-acre tract.

At December 31, 2006, MHA Petroleum Consultants, Inc. in association with Sproule Associates, Inc., our independent reserve engineering firm, assigned a total of 46.6 Bcfe of proved producing reserves to the completed East Texas wells, 28.4 Bcfe to our proved developed non-producing wells, and 181.1 Bcfe of proved undeveloped reserves to our 274 proved undeveloped locations in East Texas.

The pace of future development of this property will depend on the pace of PVOG’s activity under our joint participation agreement described above, availability of capital, future drilling results, the general economic conditions of the energy industry and on the price we receive for the natural gas and crude oil produced. Depending on rig availability and funding, in 2007, we expect PVOG to drill approximately 86 new Cotton Valley wells in the JV 30% and JV 50% Areas and we expect to drill up to 33 Cotton Valley wells in the GMXR 100% Area. We will fund our share of this drilling from internal cash flow, borrowings under our bank credit facility and other outside sources of capital including the proceeds from the common stock offering we conducted in February 2007.

The Company has drilled 3 horizontal wells to date and fracture treated 1 in 2006 and 1 in 2007. Initial production results were 1.8 MMcf per day for the first wells and 2.4 MMcf per day for the second. Both wells were drilled into the Taylor Cotton Valley Sand. The Company will complete the fracture treatment on the third well and accumulate the results before deciding on future horizontal development.

Northwestern Louisiana

The Louisiana properties are located in Clairborne, Caddo, Catahoula and Webster parishes. These properties contain approximately 600 gross (369 net) acres in the Waskom Field with production from the Cotton Valley, Hosston and Rodessa formations. We have 5 gross (2.6 net) producing wells, three of which we operate. Production is predominately oil. Louisiana proved reserves are 0.2 Bcfe and represent less than 1% of proved reserves as of December 31, 2006. Average daily production net to our interest for 2006 was 4 Bbls of oil and 22 Mcf of gas.

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Southeast New Mexico

Our Southeast New Mexico properties are located in Lea and Roosevelt counties and consist of approximately 1,920 gross (1,458 net) acres. The acreage lies on the northwestern edge of the Midland Basin, defined as the Tatum Basin. Existing production is from three zones—the Bough C, Abo and San Andres—at depths ranging from 9,500 to 10,000 feet. Proved reserves in Southeast New Mexico are 2.1 Bcfe and represent less than 1% of our total proved reserves as of December 31, 2006. Average daily production net to our interests for 2006 from our 9 gross (5.7 net) producing wells in this area was 311 Mcf of gas and 22 Bbls of oil.

We participated in the drilling of 2 gross (0.3 net) wells in 2006, with minimal results. In 2007, we do not expect to drill additional wells in New Mexico.

Reserves

As of December 31, 2006, MHA Petroleum Consultants, Inc. in association with Sproule Associates Inc. estimated our proved reserves to be 258 Bcfe. An estimated 76 Bcfe is expected to be produced from existing wells and another 182 Bcfe or 70% of the proved reserves, is classified as proved undeveloped. All of our proved undeveloped reserves are on locations that are adjacent to wells productive in the same formations. As of December 31, 2006, we had interests in 164 gross producing wells, 71 of which we operate.

The following table shows the estimated net quantities of our proved reserves as of the dates indicated and the Estimated Future Net Revenues and Present Values attributable to total proved reserves at such dates.

	Years Ended December 31,
	2004		2005		2006
Proved Developed:
Gas (MMcf)		18,980		41,503		70,801
Oil (MBbls)		584		770		947
Total (MMcfe)		22,484		46,123		76,484
Proved Undeveloped:
Gas (MMcf)		37,908		108,673		171,140
Oil (MBbls)		653		1,201		1,797
Total (MMcfe)		41,826		115,880		181,920
Total Proved:
Gas (MMcf)		56,888		150,176		241,941
Oil (MBbls)		1,237		1,971		2,744
Total (MMcfe)		64,309		162,003		258,404
Estimated Future Net Revenues1($000s)	$	214,278	$	1,648,402	$	1,577,259
Present Value1($000s)	$	83,237	$	409,624	$	262,066
Standardized Measure1 ($000s)	$	64,231	$	302,396	$	196,015

¹ The prices used in calculating Estimated Future Net Revenues and the Present Value are determined using prices as of period end. Estimated Future Net Revenues and the Present Value give no effect to federal or state income taxes attributable to estimated future net revenues. See “Note L—Supplemental Information on Oil and Gas Operations” for information about the standardized measure of discounted future net cash flows. We believe that the Estimated Future Net Revenue and Present Value are useful measures in addition to standardized measure as it assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax Present Value is based on prices and discount factors which are consistent from company to company. We also understand that securities analysts used this measure in similar ways.

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The increase in proved reserves in 2006 is primarily attributable to extensions and discoveries and revisions of prior estimates resulting from our East Texas drilling results. The decrease in Present Value and Standarized Measure in 2006 is primarily due to reduced gas prices at year end 2006 compared to 2005.

Approximately 70% of our proved reserves are undeveloped. By their nature, estimates of undeveloped reserves are less certain. In addition, the quantity and value of our proved undeveloped reserves is dependent upon our ability to fund the associated development costs which were a total of an estimated $310 million as of December 31, 2006, of which $145 million is scheduled to be expended in 2007. These estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.

The Estimated Future Net Revenues and Present Value are highly sensitive to commodity price changes and commodity prices have recently been highly volatile. The prices used to calculate Estimated Future Net Revenues and Present Value of our proved reserves as of December 31, 2006 were $58.89 per barrel for oil and $5.85 per Mmbtu for gas, adjusted for quality, contractual agreements, regional price variations and transportation and marketing fees. These period end prices are not necessarily the prices we expect to receive for our production but are required to be used for disclosure purposes by the SEC. We estimate that if all other factors (including the estimated quantities of economically recoverable reserves) were held constant, a $1.00 per Bbl change in oil prices and a $0.10 per Mcf change in gas prices from those used in calculating the Present Value would change such Present Value by approximately $982,000, and $8,930,000, respectively, as of December 31, 2006.

The estimates of proved reserves at December 31, 2006, were prepared by MHA Petroleum Consultants, Inc. in association with Sproule Associates, Inc. Sproule Associates, Inc. prepared the estimates of proved reserves as of December 31, 2004 and 2005.

No estimates of our proved reserves comparable to those included in this report have been included in reports to any federal agency other than the SEC.

Costs Incurred

The following table shows certain information regarding the costs incurred by us in our acquisition and development activities during the periods indicated. We have not incurred any exploration costs.

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	Year ended December 31,
	2004		2005		2006
Property acquisition costs:
Proved	$	—	$	—	$	—
Unproved		851,617		1,255,680		597,630
Development costs		9,152,257		25,211,613		104,657,264
Total	$	10,003,874	$	26,467,293	$	105,254,894

Drilling Results

We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling commenced. We did not acquire any wells or conduct any exploratory drilling during these periods. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and gas reserves generated by those wells.

	Year Ended December 31,
	2004				2005				2006
Development wells:	Gross		Net		Gross		Net		Gross		Net
Gas		15		4		31		16		67		35.3
Oil		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total		15		4		31		16		67		35.3

Acreage

The following table shows our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2006. Excluded is acreage in which our interest is limited to royalty, overriding royalty and other similar interests.

	Developed				Undeveloped
Location	Gross		Net		Gross		Net
East Texas and Louisiana		24,347		13,702		7,390		4,084
Southeast New Mexico		1,920		1,458		—		—
Total		26,267		15,160		7,390		4,084

Title to oil and gas acreage is often complex. Landowners may have subdivided interests in the mineral estate. Oil and gas companies frequently subdivide the leasehold estate to spread drilling risk and often create overriding royalties. When we purchased the properties, the purchase included title opinions prepared by counsel in the several states analyzing mineral ownership in each well drilled. Further, for each producing well there is a division order signed by the current recipients of payments from production stipulating their assent to the fraction of the revenues they receive. We obtain similar title opinions with respect to each new well drilled. While these practices, which are common in the industry, do not assure that there will be no claims against title to the wells or the associated revenues, we believe that we are within normal and prudent industry practices. Because many of the properties in our current portfolio were purchased out of bankruptcy in 1998, we have the advantage that any known or unknown liens against the properties were cleared in the bankruptcy.

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Productive Well Summary

The following table shows our ownership in productive wells as of December 31, 2006. Gross oil and gas wells include one well with multiple completions. Wells with multiple completions are counted only once for purposes of the following table.

	Productive Wells
Type of Well	Gross		Net
Gas		144		80.4
Oil		20		15.4
Total		164		95.8

Item 3. Legal Proceedings.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of security holders during the fourth quarter of 2006.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock

The high and low sales prices for our common stock as listed on the NASDAQ Global Market as applicable during the periods described below were as follows:

	High		Low
Year Ended December 31, 2005
First Quarter	$	13.29	$	6.22
Second Quarter		14.69		9.53
Third Quarter		27.00		13.69
Fourth Quarter		42.27		20.66
Year Ended December 31, 2006
First Quarter	$	50.50	$	28.65
Second Quarter		47.00		25.17
Third Quarter		35.12		25.40
Fourth Quarter		48.88		30.60

As of February 28, 2007, there were 23 record owners of our common stock and 6,057 beneficial owners.

We have never declared or paid any cash dividends on our shares of common stock and do not anticipate paying any cash dividends on our shares of common stock in the foreseeable future. Currently, we intend to retain any future earnings for use in the operation and expansion of our business. Any future decision to pay cash dividends on our common stock will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and other facts our board of directors may deem relevant. The payment of dividends is currently prohibited under the terms of our revolving credit facility and may be similarly restricted in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Credit Facility.”

Equity Compensation Plan Information

The following table sets forth information as of December 31, 2006 relating to equity compensation plans.

	Number of Shares to		Weighted-Average		Remaining Shares
	be Issued Upon		Exercise Price of		Available for Future
	Exercise of		Outstanding		Issuance Under Equity
Plan Category	Outstanding Options		Options		Compensation Plans
Equity Compensation Plans Approved by Shareholders		270,250	$	14.89		134,749

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Shareholder Return Performance Graph

The following graph compares the cumulative total shareholder returns of our Common Stock during the five years ended December 31, 2006 with the cumulative total shareholder returns of the Russell 2000 Index and the AMEX Oil Index. The comparison assumes an investment of $100 on December 31, 2001 in each of our Common Stock, the Russell 2000 Index and the AMEX Oil Index and that any dividends were reinvested.

Comparison of Cumulative Total Return of Our Stock, Russell 2000 Index and the AMEX Oil Index:

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among GMX Resources, Inc., The Russell 2000 Index
And The AMEX Oil Index

* $100 invested on 12/31/01 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.

Recent Sales of Unregistered Securities

None during 2006.

Purchases of Equity Securities

None during the fourth quarter of 2006.

Item 6. Selected Financial Data.

The following table presents a summary of our financial information for the periods indicated. It should be read in conjunction with our consolidated financial statements and related notes (beginning on page F-1 at the end of this report) and other financial information included herein.

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	Years Ended December 31,
	2002			2003			2004			2005			2006
Statement of Operations Data:
Oil and gas sales	$	5,970,792		$	5,367,370		$	7,689,882		$	19,026,050		$	31,882,072
Interest and other income		17,550			21,424			143,828			166,654			150,616
Total revenues		5,988,342			5,388,794			7,833,710			19,192,704			32,032,688
Lease operations		1,324,481			850,034			1,261,109			2,070,286			4,478,805
Production and severance taxes		382,825			384,069			518,721			1,241,338			464,822
General and administrative		2,577,388			1,578,865			1,985,912			3,388,396			5,828,865
Depreciation, depletion and amortization		1,901,976			1,549,678			2,043,485			3,982,079			8,046,173
Interest		510,472			439,313			558,504			142,409			824,055
Total expenses		6,697,142			4,801,959			6,367,731			10,824,508			19,642,720
Income (loss) before income taxes		(708,800	)		586,835			1,465,979			8,368,196			12,389,968
Income tax expense — current		(263,000	)		—			24,206			—			—
Income tax expense — deferred		—			—			—			1,212,100			3,415,100
Net income before cumulative effect of a change in accounting principle		(445,800	)		586,835			1,441,773			7,156,096			8,974,868
Cumulative effect of a change in accounting principle		—			(51,834	)		—			—			—
Preferred stock dividends		—			—			—			—			1,798,610
Net income (loss) applicable to common stock	$	(445,800	)	$	535,001		$	1,441,773		$	7,156,096		$	7,176,258
Net income (loss) per share — before cumulative effect	$	(.07	)	$	.09		$	.19		$	.81		$	.65
Cumulative effect		—			(.01	)		—			—			—
Net income (loss) per share — basic	$	(.07	)	$	.08		$	.19		$	.81		$	.65
Net income (loss) per share — diluted	$	(.07	)	$	.08		$	.19		$	.79		$	.64
Weighted average common shares — basic		6,550,000			6,560,000			7,396,880			8,797,529			11,120,204
Weighted average common shares — diluted		6,550,000			6,560,000			7,491,778			9,102,181			11,283,265
Statement of Cash Flows Data:
Cash provided by (used in) operating activities	$	(2,547,639	)	$	1,014,290		$	3,684,155		$	16,323,103			38,333,076
Cash provided by (used in) investing activities		1,267,831			464,315			(8,877,944	)		(39,549,002	)		(130,572,799	)
Cash provided by (used in) financing activities		1,820,000			(1,385,000	)		5,418,813			24,755,850			94,806,975
Balance Sheet Data (at end of period):
Oil and gas properties, net	$	29,359,309		$	27,660,317		$	35,956,760		$	58,927,397		$	157,300,361
Total assets		33,319,432			31,501,206			40,991,463			81,103,271			210,322,523
Long-term debt, including current portion		8,100,000			6,690,000			3,762,294			1,756,002			41,820,283
Shareholders’ equity		21,607,463			22,618,565			32,406,856			61,225,096			131,480,942

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

Summary Operating and Reserve Data

The following table presents an unaudited summary of certain operating and oil and gas reserve data for the periods indicated.

	Year Ended December 31,
	2002		2003		2004		2005		2006
Production:
Oil (MBbls)		70		35		30		48		69
Natural gas (MMcf)		1,639		917		1,049		1,930		3,915
Gas equivalent (MMcfe)		2,059		1,124		1,231		2,220		4,327
Average Sales Price:
Oil (per Bbl)	$	23.48	$	30.41	$	40.83	$	53.35	$	63.22
Natural gas (per Mcf) (1)		3.03		4.73		6.15		8.52		7.03
Average sales price (per Mcfe)	$	3.22	$	4.79	$	6.25	$	8.57	$	7.37
Operating and Overhead Costs (per Mcfe):
Lease operating expenses	$	.64	$	.74	$	1.03	$	.93	$	1.04
Production and severance taxes(2)		.19		.34		.42		.56		.11
General and administrative		1.25		1.40		1.61		1.53		1.35
Total	$	2.08	$	2.48	$	3.06	$	3.02	$	2.50
Operating Margin (per Mcfe)	$	1.14	$	2.31	$	3.19	$	5.55	$	4.87
Other (per Mcfe):
Depreciation, depletion and amortization — oil and gas production	$	.92	$	1.08	$	1.28	$	1.58	$	1.59
Estimated Net Proved Reserves (as of period-end):
Natural gas (Bcf)		56.7		45.0		56.9		150.2		241.9
Oil (MMbls)		1.7		1.3		1.2		2.0		2.7
Total (Bcfe)		66.7		53.0		64.3		162.0		258.4
Estimated Future Net Revenues ($MM)(3)(4)	$	486.3	$	178.3	$	214.3	$	1,648.9	$	1,557.3
Present Value ($MM)(3)(4)	$	80.6	$	71.2	$	83.2	$	409.6	$	262.1
Standardized measure of discounted future net cash flows ($MM)(5)	$	54.3	$	48.0	$	64.2	$	302.4	$	196.0

1	Net of results of hedging activities reduced the average gas price in 2002 by $.40 per Mcf and 2003 by $.48 per Mcf and increased the average gas price in 2006 by $0.24 per Mcf. There was no hedging activity in 2004 or 2005.
2	Production and severance taxes in 2006 reflect severance tax refunds of $1,408,433 received or accrued during the year.
3	See “Item 1 — Certain Technical Terms.”
4	The prices used in calculating Estimated Future Net Revenues and the Present Value are determined using prices as of period end. Estimated Future Net Revenues and the Present Value give no effect to federal or state income taxes attributable to estimated future net revenues. See “Item 2 — Reserves.”
5	The standardized measure of discounted future net cash flows gives effect to federal and state income taxes attributable to estimated future net revenues. See “Note L — Supplemental Information on Oil and Gas Operations.”

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Critical Accounting Policies

The preparation of the consolidated financial statements requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of our accounting estimates and judgments which management believes are most significant in its application of generally accepted accounting principles used in the preparation of the consolidated financial statements.

Full Cost Calculations

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full-cost method. We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher oil and gas depreciation, depletion and amortization rate, although this difference could change in periods of lower price environments that result in write-downs of our costs as described below.

The full cost method subjects companies to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. If our capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense. Our discounted present value of estimated future net revenues from our proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries.

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The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. There can be no assurance that significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of the full cost pool amortization.

The estimates of proved undeveloped reserve quantities and values are based on estimated future drilling which assumes that we will have the financing available to fund the estimated drilling costs. If we do not have such financing available at the time projected, the estimates of proved undeveloped reserve quantities and values will change.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed.

Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than various industry long-term price forecasts. Therefore, oil and natural gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions in the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. Depreciation, depletion and amortization expense is also based on the amount of estimated reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves changes significantly.

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. The related capitalized cost, including revisions thereto, is charged to expense through DD&A. At December 31, 2006, the Company’s balance sheet included an estimated liability for ARO of $2,162,885.

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Income Taxes

As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and accounting purposes. These differences and the net operating loss carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the consolidated statement of operations. As of December 31, 2006, we estimated that our net deferred tax liabilities were $5,026,927.

Derivative Instruments

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, we may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. We document the relationship between the derivative instrument designated as a hedge and the hedged items, as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. We assess at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of qualifying fair value hedges are recorded in earnings along with the gain or loss on the hedge item. Changes in fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Operations, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings as other income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized over the period anticipated in the original hedge transaction.

33

We do not hold or issue derivative instruments for trading purposes. Our commodity price financial swaps were designated as cash flow hedges. Changes in fair value of these derivatives were reported in “other comprehensive income” net of deferred income tax. These amounts were reclassified to oil and gas sales when the forecasted transaction took place. Our cash flow hedge was determined to be highly effective at December 31, 2006. See Note J – Hedging Activities to our consolidated financial statements.

Other

See Note A to Consolidated Financial Statements for information related to other accounting and reporting policies.

Results of Operations for the Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

Oil and Gas Sales. Oil and gas sales in the year ended December 31, 2006 increased 68% to $31,882,072 compared to the year ended December 31, 2005, due to an increase of 95% in production and a 14% decrease in the average oil and gas price. The average price per barrel of oil and mcf of gas received in 2006 was $63.22 and $7.03, respectively, compared to $53.35 and $8.52 in the year of 2005. Oil production for 2006 increased 21 MBbls to 69 MBbls compared to 2005. Gas production increased to 3,915 MMcf compared to 1,930 MMcf for the year of 2005, an increase of 103%. Increased production in 2006 resulted from drilling and completing new wells during the year.

Lease Operations. Lease operations expense increased $2,408,519 in 2006 to $4,478,805, a 116% increase compared to 2005. Increased expenses resulted from re-works of wells and additional costs to operate new wells. Lease operations expense on an equivalent unit of production basis was $1.04 per Mcfe in 2006 compared to $.93 per Mcfe for 2005, which increased due to new wells and well workovers.

Production and Severance Taxes. Production and severance taxes decreased 63% to $464,822 in 2006 compared to $1,241,338 in 2005. Production and severance taxes are assessed on the value of the oil and gas produced. The decrease in production and severance taxes in 2006 is due to severance tax refunds of $1,408,433 that were received or accrued during the year. Upon approval by the State of Texas, certain wells are exempt from severance taxes for a period of ten years and this will reduce our expense going forward.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense increased $4,064,094 to $8,046,173 in 2006, up 102% from 2005. This increase is due primarily to an increase in production for 2006. The oil and gas depreciation, depletion and amortization rate per equivalent unit of production was $1.59 per Mcfe in 2006 compared to $1.58 per Mcfe in 2005. Drilling and completion costs in the field were increased and were primarily the reason for increase.

Interest. Interest expense for 2006 was $824,055 compared to $142,409 for 2005. This increase is primarily attributable to the increased amount of debt outstanding during 2006.

34

General And Administrative Expense.General and administrative expense for 2006 was $5,828,865 compared to $3,388,396 for 2005, an increase of 72%. This increase of $2,440,469 was the result of a change in accounting principle relating to stock options, increases in staff necessary to operate at higher levels of drilling and production, and costs incurred to comply with Sarbanes Oxley Section 404 requirements. General and administrative expense per equivalent unit of production was $1.35 per Mcfe for 2006 compared to $1.53 per Mcfe for 2005, reflecting slightly improved efficiency levels.

Income Taxes. Income tax for 2006 was $3,415,100 as compared to $1,212,100 in 2005. A deferred non-cash tax provision was booked for 2006 reflecting a 28% effective rate. We expect our deferred non-cash tax provision to continue to increase in 2007.

Net Income and Net Income Per Share.For 2006, we reported net income of $7,176,258 after preferred dividends at $1,798,610 compared to $7,156,096 for 2005. Net income per basic and fully diluted share was $0.65 and $0.64, respectively, in 2006 compared to $0.81 and $0.79 in 2005, respectively. Weighted average fully-diluted shares outstanding increased by 24% from 9,102,181 in 2005 to 11,283,265 in 2006.

Results of Operations for the Year Ended December 31, 2005 Compared to the Year Ended December 31, 2004

Oil and Gas Sales.Oil and gas sales in the year ended December 31, 2005 increased 147% to $19,026,050 compared to the year ended December 31, 2004, due to an increase of 80% in production and a 36% increase in the average oil and gas price. The average price per barrel of oil and Mcf of gas received in 2005 was $53.35 and $8.52, respectively, compared to $40.83 and $6.15 in the year 2004. Oil production for 2005 increased 18 MBbls to 48 MBbls compared to 2004. Gas production increased to 1,930 MMcf compared to 1,049 MMcf for the year of 2004, an increase of 84%. Increased production in 2005 resulted from drilling and recompleting new wells during the year.

Lease Operations.Lease operations expense increased $809,177 in 2005 to $2,070,286, a 64% increase compared to 2004. Increased expenses resulted from numerous re-works of wells and additional costs of new wells. Lease operations expense on an equivalent unit of production basis was $.93 per Mcfe in 2005 compared to $1.03 per Mcfe for 2004, which decreased due to new wells.

Production and Severance Taxes. Production and severance taxes increased 139% to $1,241,338 in 2005 compared to $518,721 in 2004. Production and severance taxes are assessed on the value of the oil and gas produced. As a result, the increase resulted primarily from the increase in oil and gas sales prices and an increase in production.

Depreciation, Depletion and Amortization. Depreciation depletion and amortization expense increased $1,938,594 to $3,982,079 in 2005, up 95% from 2004. This increase is due primarily to an increase in production for 2005. The oil and gas depreciation, depletion and amortization rate per equivalent unit of production was $1.58 per Mcfe in 2005 compared to $1.28 per Mcfe in 2004. Drilling and completion costs in the field were increased and were primarily the reason for increase.

Interest. Interest expense for 2005 was $142,409 compared to $558,504 for 2004. This decrease is primarily attributable to the reduced amount of debt.

35

General And Administrative Expense.General and administrative expense for 2005 was $3,388,396 compared to $1,985,912 for 2004, an increase of 71%. This increase of $1,402,484 was the result of an increase in staff necessary to operate at higher levels of drilling and production. General and administrative expense per equivalent unit of production was $1.53 per Mcfe for 2005 compared to $1.61 per Mcfe for 2004, reflecting slightly improved efficiency levels.

Income Taxes. Income tax for year of 2005 was $1,212,100 as compared to $24,206 in 2004. A deferred non-cash tax provision was booked for 2005 reflecting a 15% effective rate.

Net Income and Net Income Per Share. For 2005, we reported net income of $7,156,096 compared to $1,444,773 for 2004. Net income per fully diluted share was $.79 in 2005 compared to $.19 in 2004, up 316%, while weighted average fully-diluted shares outstanding increased by 22% from 7,491,778 in 2004 to 9,102,181 in 2005.

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our investment activities. Our cash flows from operating activities are substantially dependent upon oil and gas prices and significant decreases in market prices of oil or gas could result in reductions of cash flow and affect the amount of our capital investment.

Cash Flow—Year Ended December 31, 2006 Compared to Year Ended December 31, 2005.In 2006 we had a positive cash flow from operating activities of $38,333,076 as a result of increased production volume during 2006. Our cash flow from operating activities in 2005 was $16,323,103. Cash flow from operating activities before increase in working capital was $21,128,092 compared to $12,462,625 in 2005. This resulted from a 95% increase in oil and gas sales in 2006. We received a net $94,806,975 in cash from financing activities in 2006 compared to 2005 amounts of $24,755,850. The cash flow from financing activities in 2006 was primarily from the sale of preferred stock of $47,113,197, the sale of common stock of $14,528,107, and additional debt. The cash inflow in 2005 from financing activities primarily resulted from the sale of common stock of $21,662,143 and additional debt.

Cash Flow—Year Ended December 31, 2005 Compared to Year Ended December 31, 2004.In 2005 we had a positive cash flow from operating activities of $16,323,103 as a result of increased production volume and increased oil and gas prices during 2005. Our cash flow from operating activities in 2004 was $3,684,155. Cash flow from operating activities before increase in working capital was $12,462,625 compared to $3,812,020 in 2004. This resulted from a 80% increase in oil and gas sales in 2005. We received a net $24,755,850 in cash from financing activities in 2005 compared to 2004 amounts of $5,418,513. The cash inflow from financing activities in 2005 was primarily from the sale of common stock of $21,662,143 and additional debt. The cash flow in 2004 from financing activities primarily resulted from sales of common stock in the amount of $8,346,518 and repayment of debt.

36

Credit Facility

In July 2005, we executed a loan agreement with Hibernia National Bank, now known as Capital One National Association (“Lender”) providing for a secured revolving line of credit up to an amount established as the borrowing base from time to time based on a periodic evaluation of our oil and gas reserves (the “Borrowing Base”). The loan bears interest at the rate elected by us of either the prime rate as published in the Wall Street Journal (payable monthly) or the LIBO rate plus a margin ranging from 1.5% to 2.25% based on the amount of the loan outstanding in relation to the Borrowing Base for a period of one, two or three months (payable at the end of such period). Principal is payable voluntarily by us or is required to be paid (i) if the loan amount exceeds the Borrowing Base; (ii) if the Lender elects to require periodic payments as a part of a Borrowing Base re-determination; and (ii) at the maturity date of July 29, 2008. We are obligated to pay a facility fee equal to 0.25% per year of the unused portion of the Borrowing Base payable quarterly. On June 7, 2006, the loan was amended to add Union Bank of California, N.A., as a lender. The Borrowing Base has been adjusted from time to time and was $50,000,000 at December 31, 2006. The loan is secured by a first mortgage on substantially all of our oil and gas properties, a pledge of our ownership of the stock of our subsidiaries, a guaranty from our subsidiaries and a security interest in all of the assets of our subsidiaries.

In addition to customary reporting and compliance requirements, the principal covenants under the new credit facility are:

1. Maintain a current ratio of not less than 1 to 1;

2. Maintain a minimum net worth of $69.8 million as of March 31, 2006 adjusted annually to add 50% of our net income for the prior fiscal year and 100% of net proceeds of equity offerings;

3. Maintain on a quarterly basis a rolling four quarter ratio of EBITDA to interest expense and preferred dividends of not less than 3 to 1;

4. Maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the Borrowing Base;

5. Pay all accounts payable within 60 days of the due date other than those being contested in good faith;

6. Not incur any other debt other than as permitted by the loan agreement, which includes qualified subordinated debt and qualified redeemable preferred equity of up to $50 million;

7. Not permit any liens other than those permitted by the loan agreement;

8. Not make any investments, loans or advances other than as permitted by the loan agreement, which includes permitted investment in Diamond Blue Drilling subject to certain limitations;

9. Not engage in any mergers or consolidations or sales of all or substantially all of our assets;

37

10. Not pay any dividends on common stock or make any other distributions with respect to our stock, including stock repurchases;

11. Not permit either Ken L. Kenworthy Jr. or Ken L. Kenworthy Sr. to cease being an executive officer unless a suitable replacement is employed within 4 months; and

12. Not permit a person or group (other than existing management) to acquire more than 33% of the outstanding common stock or otherwise suffer a change in control.

As of December 31, 2006, we had $40,000,000 outstanding under the facility.

Other Financing – 2006 and 2007

Warrant Exercises.Our Class A warrants to purchase common stock at $12.00 per share issued in our initial public offering in 2001 expired in February 2006. In 2006, prior to the expiration of the warrants, we received approximately $14 million in exercise proceeds and issued an additional 1,164,326 shares of common stock.

Preferred Stock Issuance. In August 2006, we made a public offering of 2,000,000 shares of cumulative preferred stock for $50,000,000. Net proceeds of $47,113,197 were used primarily to fund drilling and development activity in our East Texas properties and for other general corporate purposes.

Common Stock Sale and Issuance. In February 2007, we completed a public offering of 2,000,000 shares of our common stock for $34.82 per share. Net proceeds to us were approximately $65,500,000, which we plan to use to fund drilling and development of our East Texas properties and for other general corporate purposes. Pending such uses, a portion of the net proceeds from this offering will be used to reduce indebtedness under our revolving bank credit facility, which will permit additional borrowings in the future under the terms of our bank credit facility.

Working Capital

At December 31, 2006, we had a working capital deficit of $15,349,672. Including availability under our credit facility, our working capital deficit as of December 31, 2006 would have been $5,349,672.

Commitments and Capital Expenditures

The following table reflects the Company’s contractual obligations as of December 31, 2006.

	Payments Due by Period
			Less than						More than
Contractual Obligations	Total		1 year		1-3 years		3-5 years		5 years
Long-term debt	$	40,000,000	$	—	$	40,000,000	$	—	$	—
Operating leases		564,950		190,611		339,526		34,813		—
75% PVOG Financing1		1,820,283		251,447		386,985		318,884		862,967
Total	$	42,385,233	$	442,058	$	40,726,511	$	353,697	$	862,967

¹ PVOG financing is payable out of 75% of revenues from the wells financed and repayment is based on estimated production which may vary from actual.

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Other than obligations under our credit facility, the PVOG financing and operating leases, our commitments for capital expenditures relate to development of oil and gas properties. We will not enter into drilling or development commitments until such time as a source of funding for such commitments is known to be available, either through financing proceeds, joint venture arrangements, internal cash flow, additional funding under our bank credit facility or working capital. Our participation agreement with PVOG permits us to terminate multiple rig operations by PVOG on 60 days notice.

Liquidity and Financing Considerations

We have projected capital expenditures in 2007 ranging from $145 to $175 million. We expect production from our wells drilled and completed in 2005 and 2006 to provide cash flow to support additional drilling in 2007 and beyond. Our 2006 cash flow was significantly greater than 2005. The indebtedness under the credit facility of $40,000,000 at December 31, 2006, was repaid in full from the proceeds of a 2007 stock offering. Therefore, we will have availability under our credit facility ($50 million as of March 1, 2007 based on the last Borrowing Base determination of $50 million effective as of December 21, 2006) and expect that increases in the Borrowing Base may occur during the year as additional production is established. As a result, we believe we could fund from these sources from $150 to $175 million in capital expenditures, depending on gas prices and drilling results. To fund our drilling plans at the high end of the range, we would need additional financing from drilling funds or debt placements. We do not anticipate issuing additional common stock in 2007 to fund drilling.

2007 Guidance

We estimate first quarter 2007 production to be 1.6 Bcfe and total 2007 production to be 8.6 Bcfe.

Recently Issued Accounting Pronouncements

See Note A to Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements to enhance our liquidity and capital resources position or for any other purpose.

Price Risk Management

See Item 7A – Quantitative and Qualitative Disclosures About Market Risk.

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Forward-Looking Statements

All statements made in this document other than purely historical information are “forward looking statements” within the meaning of the federal securities laws. These statements reflect expectations and are based on historical operating trends, proved reserve positions and other currently available information. Forward looking statements include statements regarding future plans and objectives, future exploration and development expenditures and number and location of planned wells and statements regarding the quality of our properties and potential reserve and production levels. These statements may be preceded or followed by or otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “continues,” “plans,” “estimates,” “projects” or similar expressions or statements that events “will,” “should,” “could,” “might” or “may” occur. Except as otherwise specifically indicated, these statements assume that no significant changes will occur in the operating environment for oil and gas properties and that there will be no material acquisitions or divestitures except as otherwise described.

The forward-looking statements in this report are subject to all the risks and uncertainties which are described in this document. We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and are not taken into consideration in the forward-looking statements.

For all of these reasons, actual results may vary materially from the forward looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

There are a number of risks that may affect our future operating results and financial condition. See “Item 1A. Risk Factors.”

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

Commodity Price Risk

We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Reductions in crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

In the past, we have entered into financial price risk management activities with respect to a portion of projected oil and gas production through financial price swaps whereby we received a fixed price for our production and pay a variable market price to the contract counterparty. These activities are intended to reduce our exposure to oil and gas price fluctuations. We have entered into these instruments in 2006. In addition, our credit facility requires us to maintain a hedging program on mutually acceptable terms whenever the loan amount outstanding exceeds 75% of the Borrowing Base, which could occur in 2007. The gains and losses realized as a result of these activities are substantially offset in the cash market when the commodity is delivered. Following is a summary of the current natural gas swaps we have in place as of March 1, 2007:

40

					Remaining
			Notional Amount		Notional Amount
			Per Month		as of December 31,		Fixed Price
Effective Date	Maturity Date		(MMBtu)		2006 (MMBtu)		per MMBtu
8/1/2006		7/31/2007		100,000		700,000	$	8.005
2/1/2007		12/31/2008		200,000		4,600,000	$	7.460
8/1/2007		12/31/2008		100,000		1,700,000	$	7.600

All contracts are based on Houston Ship Channel Index Prices which historically have had a high degree of correlation with the actual prices received by the Company.

The fair value of our natural gas swaps in effect at December 31, 2006 was $1,175,669, assuming that gas prices in effect at December 31, 2006 remain in effect for the life of the swap. Based on the monthly notional amount in effect at December 31, 2006, a hypothetical $1 increase in natural gas prices would have decreased the cash flow and earnings from our swap by $100,000 per month and a $1 decrease in natural gas prices would increase the cash flow and earnings from our swap by $100,000 per month.

Interest Rate Risk

As of December 31, 2006, we had $40 million of long-term debt outstanding under our credit facility. The credit facility matures in July 2008 and is governed by a borrowing base calculation that is redetermined periodically. We have the option to elect interest at (1) LIBOR plus 1.50% to 2.25% depending on the level of borrowings relative to the borrowing base or (2) prime rate. As a result, our interest costs fluctuate based on short-term interest rates relating to our credit facility. Based on borrowings outstanding at December 31, 2006, a 100 basis point change in interest rates would change our interest expense by approximately $400,000. We had no interest rate derivatives during 2006.

Item 8. Financial Statements and Supplementary Data.

Our consolidated financial statements are presented beginning on page F-1 found at the end of this report.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures.

Controls and Procedures

Our principal executive officer and principal financial officer have evaluated our disclosure controls and procedures (as defined in rules adopted by the Securities and Exchange Commission) as of December 31, 2006, and have concluded that these controls and procedures are effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. These disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit is accumulated and communicated to management, including the principal executive officer and the principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

41

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2006, no change occurred in our internal control over financial reporting that materially affected, or is likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we evaluated the effectiveness of the design and operation of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of December 31, 2006 as reflected in our report included in Item 8.

Smith, Carney & Co., p.c., our independent registered public accounting firm, audited management’s assessment of the effectiveness of internal control over financial reporting and, based on that audit, issued the report set forth in Item 8.

Certifications

Our chief executive and chief financial officers have completed the certifications required to be filed as an Exhibit to this Report (See Exhibits 31.1 and 31.2) relating to the design of our disclosure controls and procedures and the design of our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

In accordance with the provisions of General Instruction G(3), information required by Items 10 through 14 of Form 10-K are incorporated herein by reference to the Company’s Proxy Statement for the Annual Meeting of Shareholders to be filed prior to April 30, 2007.

43

PART IV

Item 15. Exhibits and Financial Statement Schedules.

The following documents are filed as part of this report.

1.	Financial Statements: See Index to Consolidated Financial Statements and Consolidated Financial Statement Schedule set forth on page F-1 of this report.
2.	Exhibits: For a list of documents filed as exhibits to this report, see the Exhibit Index immediately preceding the Exhibits filed with this report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this amended report to be signed on its behalf by the undersigned, thereunto duly authorized.

	GMX RESOURCES INC.
Dated: January 23, 2008	By:	/s/ Ken L. Kenworthy, Jr.
		Ken L. Kenworthy, Jr., President

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

Signatures	Title	Date
/s/ Ken L. Kenworthy, Jr.Ken L. Kenworthy, Jr.	President and Director (Principal Executive Officer)	January 23, 2008
/s/ Ken L. Kenworthy, Sr.Ken L. Kenworthy, Sr.	Executive Vice President, Chief Financial Officer and Director (Principal Financial and Accounting Officer)	January 23, 2008
/s/ T. J. BoismierT. J. Boismier	Director	January 23, 2008
/s/ Steven CraigSteven Craig	Director	January 23, 2008
/s/ Jon W. McHughJon W. McHugh	Director	January 23, 2008

45

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Management’s Annual Report on Internal Control over Financial Reporting	F-4
Consolidated Balance Sheets, December 31, 2005 and 2006	F-5
Consolidated Statements of Operations, Years Ended December 31, 2004, 2005 and 2006	F-6
Consolidated Statements of Changes in Shareholders’ Equity, Years Ended December 31, 2004, 2005 and 2006	F-7
Consolidated Statements of Cash Flows, Years Ended December 31, 2004, 2005 and 2006	F-8
Consolidated Statements of Comprehensive Income, Years Ended December 31, 2004, 2005 and 2006	F-9
Notes to Consolidated Financial Statements	F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To: The Board of Directors and Shareholders
GMX Resources Inc. and Subsidiaries

We have audited the accompanying balance sheets ofGMX Resources Inc.and Subsidiariesas of December 31, 2005 and 2006, and the related statements of operations, shareholders’ equity, cash flows, and comprehensive income for each of the years in the three-year period ended December 31, 2006. We also have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, thatGMX Resources Inc. and Subsidiariesmaintained effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).GMX Resources 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, an opinion on management’s assessment, and an opinion on the effectiveness of 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 audit of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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.

F-2

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 ofGMX Resources Inc. and Subsidiariesas of December 31, 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, management’s assessment thatGMX Resources Inc. and Subsidiariesmaintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Furthermore, in our opinion,GMX Resources Inc. and Subsidiariesmaintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Smith, Carney & Co., p.c.                                             

Oklahoma City, Oklahoma
March 13, 2007

F-3

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, our management has conducted an assessment, including testing, using the criteria inInternal Control–Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our 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.

Based on the assessment, our management has concluded that we maintained effective internal control over financial reporting as of December 31, 2006, based on criteria inInternal Control–Integrated Frameworkissued by COSO. Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006, has been audited by Smith, Carney & Co., p.c., an independent registered public accounting firm, as stated in their report which is included herein.

Our management, including our chief executive officer and chief financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected.

F-4

GMX Resources Inc. and Subsidiaries
Consolidated Balance Sheets

	December 31,
	2005			2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,392,497		$	4,959,749
Accounts receivable—interest owners		74,971			64,185
Accounts receivable—oil and gas revenues		4,188,451			5,766,286
Derivative instruments		—			1,175,669
Inventories		247,364			373,420
Prepaid expenses and deposits		10,028			1,284,904
Total current assets		6,913,311			13,624,213
OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD OF ACCOUNTING
Properties being amortized		67,130,448			173,050,284
Properties not subject to amortization		1,789,816			1,124,873
Less accumulated depreciation, depletion, and amortization		(9,992,867	)		(16,874,796	)
		58,927,397			157,300,361
OTHER PROPERTY AND EQUIPMENT		17,044,734			43,097,326
Less accumulated depreciation		(1,793,781	)		(3,742,057	)
		15,250,953			39,355,269
OTHER ASSETS		11,610			42,680
TOTAL ASSETS	$	81,103,271		$	210,322,523
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	7,809,387		$	24,658,305
Accrued expenses		419,130			3,236,536
Accrued interest		25,430			314,181
Revenue distributions payable		317,232			513,416
Short-term loan		5,100,000			—
Current portion of long-term debt		345,967			251,447
Total current liabilities		14,017,146			28,973,885
LONG-TERM DEBT, LESS CURRENT PORTION		1,410,035			41,568,836
OTHER LIABILITIES		3,238,894			3,271,933
DEFERRED INCOME TAXES		1,212,100			5,026,927
SHAREHOLDERS’ EQUITY:
Preferred stock, par value $.001 per share, 10,000,000 shares authorized:
Series A Junior Participating Preferred Stock 25,000 shares authorized, none issued and outstanding		—			—
9.25% Series B Cumulative Preferred Stock, 3,000,000 Shares authorized, 2,000,000 shares issued and outstanding (aggregate liquidation preference $50,000,000)		—			2,000
Common stock, par value $.001 per share–authorized 50,000,000 shares issued and outstanding 9,975,315 shares in 2005 and 11,242,136 shares in 2006		9,975			11,242
Additional paid-in capital		50,965,235			113,265,614
Retained earnings		10,249,886			17,426,144
Other comprehensive income		—			775,942
Total shareholders’ equity		61,225,096			131,480,942
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	81,103,271		$	210,322,523

See accompanying notes to consolidated financial statements.

F-5

GMX Resources Inc. and Subsidiaries
Consolidated Statements of Operations

	Year Ended December 31,
	2004		2005		2006
REVENUE:
Oil and gas sales	$	7,689,882	$	19,026,050	$	31,882,072
Interest income		14,498		161,434		150,285
Other income		129,330		5,220		331
Total revenue		7,833,710		19,192,704		32,032,688
EXPENSES:
Lease operations		1,261,109		2,070,286		4,478,805
Production and severance taxes		518,721		1,241,338		464,822
Depreciation, depletion and amortization		2,043,485		3,982,079		8,046,173
Interest		558,504		142,409		824,055
General and administrative		1,985,912		3,388,396		5,828,865
Total expenses		6,367,731		10,824,508		19,642,720
Income before income taxes		1,465,979		8,368,196		12,389,968
INCOME TAXES		24,206		1,212,100		3,415,100
NET INCOME		1,441,773		7,156,096		8,974,868
Preferred stock dividends		—		—		1,798,610
NET INCOME APPLICABLE TO COMMON STOCK	$	1,441,773	$	7,156,096	$	7,176,258
Earnings per share – Basic	$	0.19	$	0.81	$	0.65
Earnings per share – Diluted	$	0.19	$	0.79	$	0.64
Weighted average common shares – Basic		7,396,880		8,797,529		11,120,204
Weighted average common shares – Diluted		7,491,778		9,102,181		11,283,265
See accompanying notes to consolidated financial statements.

F-6

GMX Resources Inc. and Subsidiaries

Consolidated Statement of Changes in Shareholders’ Equity

Years Ended December 31, 2004, 2005, and 2006

																	Other
											Additional						compre-		Total
	Preferred		Common			Preferred		Common			paid-in			Retained			hensive		shareholders’
	shares		shares			par value		par value			capital			earnings			income		equity
BALANCE AT DECEMBER 31, 2003		—		6,575,000		$	—	$	6,575		$	20,959,973		$	1,652,017		$	—	$	22,618,565
Options Exercised		—		15,000			—		15			14,985			—			—		15,000
Redeemed & Cancelled Warrants		—		—			—		—			(118,712	)		—			—		(118,712	)
Warrants Granted		—		—			—		—			257,250			—			—		257,250
Warrants Exercised		—		163,540			—		164			177,398			—			—		177,562
Shares Issued		—		1,300,000			—		1,300			8,014,118			—			—		8,015,418
Net income		—		—			—		—			—			1,441,773			—		1,441,773
BALANCE AT DECEMBER 31, 2004		—		8,053,540		$	—	$	8,054		$	29,305,012		$	3,093,790		$	—	$	32,406,856
Options Exercised		—		128,250			—		128			422,787			—			—		422,915
Redeemed & Cancelled Warrants		—		(144,180	)		—		(144	)		(774,134	)		—			—		(774,278	)
Warrants Granted		—		—			—		—			—			—			—		—
Warrants Exercised		—		337,705			—		337			1,666,898			—			—		1,667,235
Shares Issued		—		1,600,000			—		1,600			20,344,672			—			—		20,346,272
Net Income		—		—			—		—			—			7,156,096			—		7,156,096
BALANCE AT DECEMBER 31, 2005		—		9,975,315		$	—	$	9,975		$	50,965,235		$	10,249,886		$	—	$	61,225,096
Stock Options Exercised		—		102,500			—		103			555,065			—			—		555,168
Warrants Exercised		—		1,164,321			—		1,164			13,971,776			—			—		13,972,940
Stock Option Compensation Expense		—		—			—		—			662,341			—			—		662,341
Series B Preferred Shares Issued		2,000,000		—			2,000		—			47,111,197			—			—		47,113,197
Preferred Stock Dividends		—		—			—		—			—			(1,798,610	)		—		(1,798,610	)
Unrealized Gain on Derivative Instruments		—		—			—		—			—			—			775,942		775,942
Net Income		—		—			—		—			—			8,974,868			—		8,974,868
BALANCE AT DECEMBER 31, 2006		2,000,000		11,242,136		$	2,000	$	11,242		$	113,265,614		$	17,426,144		$	775,942	$	131,480,942

See accompanying notes to consolidated financial statements.

F-7

GMX Resources Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2004			2005			2006
CASH FLOWS DUE TO OPERATING ACTIVITIES
Net income	$	1,441,773		$	7,156,096		$	8,974,868
Adjustments to reconcile net income to net cash provided by operating activities;
Depreciation, depletion, and amortization		2,043,485			3,982,080			8,046,173
Amortization of loan fees		326,762			112,349			29,610
Deferred income taxes		—			1,212,100			3,415,100
Non cash stock compensation expense		—			—			662,341
Decrease (increase) in:
Accounts receivable		(865,035	)		(2,666,101	)		(1,567,049	)
Inventory and prepaid expenses		(431,908	)		(56,852	)		(1,430,543	)
Other assets		—			43,273			(31,070	)
Increase (decrease) in:
Accounts payable		1,187,017			5,487,870			16,848,918
Accrued expenses and other liabilities		40,128			309,842			3,106,157
Revenue distributions payable		(58,067	)		742,446			278,571
Net cash provided by operating activities		3,684,155			16,323,103			38,333,076
CASH FLOWS DUE TO INVESTING ACTIVITIES
Additions to oil and gas properties		(8,543,367	)		(26,019,690	)		(104,412,090	)
Purchase of property and equipment		(334,577	)		(13,529,312	)		(26,160,709	)
Net cash provided by (used in) investing activities		(8,877,944	)		(39,549,002	)		(130,572,799	)
CASH FLOWS DUE TO FINANCING ACTIVITIES
Advance on borrowings		3,872,457			10,701,763			78,861,250
Payments on debt		(6,800,162	)		(7,608,056	)		(43,896,969	)
Proceeds from sale of common stock		8,346,518			21,662,143			14,528,107
Proceeds from sale of Series B preferred stock		—			—			47,113,197
Dividends paid on Series B preferred stock		—			—			(1,798,610	)
Net cash provided by financing activities		5,418,813			24,755,850			94,806,975
NET INCREASE IN CASH		225,024			1,529,951			2,567,252
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		637,522			862,546			2,392,497
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	862,546		$	2,392,497		$	4,959,749
CASH PAID FOR INTEREST	$	261,445		$	116,979		$	683,486
CASH PAID FOR INCOME TAXES	$	24,206		$	—		$	—

See accompanying notes to consolidated financial statements.

F-8

GMX Resource Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

	Year Ended December 31,
	2004		2005		2006
Net Income	$	1,441,773	$	7,156,096	$	8,974,868
Other comprehensive income tax:
Change in fair value of derivative instruments		—		—		2,115,169
Adjustment for derivative gains reclassified into oil and gas sales		—		—		(939,500	)
Other comprehensive income, before income tax		—		—		1,175,669
Income tax provision related to items of other comprehensive income		—		—		(399,727	)
Other comprehensive income, net of income tax		—		—		775,942
Comprehensive income	$	1,441,773	$	7,156,096	$	9,750,810

See accompanying notes to consolidated financial statements.

F-9

GMX Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2004, 2005 and 2006

NOTE A—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the accounts ofGMX Resources Inc.(the “Company or GMX”) and its wholly owned subsidiaries, Endeavor Pipeline, Inc. and Diamond Blue Drilling Co. Endeavor Pipeline, Inc. owns and operates natural gas gathering facilities in East Texas. Diamond Blue Drilling Co. owns drilling rigs and drills oil and gas wells exclusively for GMX. All significant intercompany accounts and transactions have been eliminated. Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly described below.

ORGANIZATION: The Company was formed in January 1998. The Company is primarily engaged in acquisition, exploration, and development of properties for the production of crude oil and natural gas in Texas, Louisiana and New Mexico.

CASH AND CASH EQUIVALENTS: GMX considers all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.

INVENTORIES: Inventories consist of lease and well equipment and crude oil on hand. The Company uses lease and well equipment in its ongoing operations and it is carried at the lower of cost or market. Treated and stored crude oil inventory on hand at the end of the year is valued at the lower of cost or market.

PROPERTY AND EQUIPMENT: The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment are capitalized. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Capitalized costs are subject to a “ceiling test,” which basically limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of the estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves less any related income tax effects. Capitalized costs are depleted by an equivalent unit-of-production method, converting oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. Revenues from services provided to working interest owners of properties in which GMX also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and gas properties.

F-10

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

Depreciation and amortization of other property and equipment, including leasehold improvements and buildings, are provided using the straight-line method based on estimated useful lives from five to 20 years.

Pipeline and gathering system assets and other long-lived assets are periodically assessed to determine if circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” This statement requires (a) recognition of an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) measurement of an impairment loss as the difference between the carrying amount and fair value of the asset.

LOAN FEES: Included in other assets are costs associated with long-term debt. These costs are being amortized over the life of the loan using a method that approximates the interest method.

REVENUE AND ROYALTY DISTRIBUTIONS PAYABLE: For certain oil and natural gas properties, GMX receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue distributions payable in the accompanying balance sheets. GMX accrues revenue for only its net interest in oil and gas properties.

REVENUE RECOGNITION AND NATURAL GAS BALANCING: Oil and gas revenues are recognized when sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. During the course of normal operations, the Company and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over the lives of the wells’ production capability. If an imbalance exists at the time the wells’ reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements.

The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company’s excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. There are no significant imbalances as of December 31, 2005 or 2006.

CAPITALIZED INTEREST: Interest of $31,170 and $110,929 was capitalized related to the unproved properties that were not being currently depreciated, depleted, or amortized and on which development activities were not in progress in 2005 and 2006, respectively. In addition, the Company capitalized interest of $83,692 during 2006 related to the construction of two drilling rigs. Interest is capitalized to the cost of the rig while it is being built and prior to it being placed into service.

INCOME TAXES: The Company accounts for income taxes using the asset and liability method. Under the asset and liability method, deferred tax assets and liabilities are recognized at the enacted tax rates for the future tax consequences attributable to differences between the financial carrying amounts of existing assets and liabilities and the respective tax bases and tax operating losses and tax credit carryforwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

F-11

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

HEDGING AND RISK MANAGEMENT ACTIVITIES: The Company may enter into oil and gas price swaps to manage its exposure to oil and gas price volatility. The instruments are usually placed with counterparties that the Company believes are minimal credit risks. The oil and gas reference prices upon which the risk management instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, we may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. We document the relationship between the derivative instrument designated as a hedge and the hedged items, as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. We assess at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of qualifying fair value hedges are recorded in earnings along with the gain or loss on the hedge item. Changes in fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Operations, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings as other income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized over the period anticipated in the original hedge transaction.

The Company does not hold or issue derivative instruments for trading purposes. The Company’s commodity price financial swaps were designated as cash flow hedges. Changes in fair value of these derivatives were reported in “other comprehensive income” net of deferred income tax. These amounts were reclassified to oil and gas sales when the forecasted transaction took place. The Company’s cash flow hedge was determined to be highly effective at December 31, 2006. See NOTE J – HEDGING ACTIVITIES.

GENERAL AND ADMINISTRATIVE EXPENSES: General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and gas properties operated by the Company and net of amounts capitalized pursuant to the full cost method of accounting.

F-12

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

USE OF ESTIMATES: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions that affect the amounts reported. The actual results could differ from those estimates, including useful lives of property and equipment, oil and gas reserve quantities, and expenses associated with asset retirements as well as expected volatility and contract term to exercise outstanding stock options.

FAIR VALUE OF FINANCIAL INSTRUMENTS: The Company’s financial instruments consist of cash, accounts receivable, accounts payable, accrued expenses, accrued interest, revenue distributions payable, short and long-term debt, and a natural gas price swap. Fair value of non-derivative financial instruments approximate carrying value due to the short-term nature of these instruments. Since the interest rate on the long-term debt reprices frequently, the fair value of the long-term debt approximates the carrying value.

BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE: Basic earnings per share (“EPS”) of common stock have been computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of common stock includes the effect of outstanding stock options and warrants which are dilutive.

The table below reflects the amount of options not included in the diluted EPS calculation above, as they were antidilutive.

	2005		2006
Options excluded from dilution calculation		77,000		25,000
Range of exercise prices		$20.01-$29.00		$39.65
Weighted average exercise price		$20.98		$39.65

STOCK BASED COMPENSATION: Effective January 1, 2006, GMX adopted SFAS No. 123(R),Share-Based Payment, (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires equity-classified share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized in compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon GMX’s adoption of SFAS No. 123(R).

GMX recognized $662,341 of stock compensation expense in 2006. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. The Company recorded an income tax benefit of approximately $166,000 related to the share based compensation expense recognized during 2006.

Prior to adopting SFAS No. 123(R), GMX accounted for its fixed-plan employee stock options using the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees, (“APB No. 25”) and related interpretations. This method required compensation expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

F-13

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

Had GMX elected the fair value provisions of SFAS No. 123(R) in 2004 and 2005, GMX’s net income and net income per share would have differed from the amounts actually reported as shown in the following table:

	Year Ended			Year Ended
	December 31, 2004			December 31, 2005
Net income as reported	$	1,441,773		$	7,156,096
Add: Stock-based compensation recognized		—			163,379
Deduct: Stock-based compensation, net of tax		(316,085	)		(467,085	)
Pro forma net earnings	$	1,125,688		$	6,852,390
Pro forma earnings per share – basic:	$	0.15		$	0.78
Pro forma earnings per share – diluted	$	0.15		$	0.75

The following table provides information related to stock option activity during 2004, 2005 and 2006:

				Weighted
	Number of			average exercise
	shares			price
Balance as of December 31, 2003		139,000		$	5.69
Granted		190,000			3.83
Exercised		(15,000	)		1.00
Forfeited		—			—
Expired		—			—
Balance as of December 31, 2004		314,000		$	3.67
Granted		137,000			16.58
Exercised		(128,250	)		2.69
Forfeited		—			—
Expired		—			—
Balance as of December 31, 2005		322,750		$	8.65
Granted		53,000			35.31
Exercised		(102,500	)		5.42
Forfeited		(3,000	)		27.91
Expired		—			—
Balance as of December 31, 2006		270,250		$	14.89

At December 31, 2006, there were 59,250 exercisable options with weighted average exercise price of $9.77.

The weighted-average remaining contractual life of outstanding and exercisable options at December 31, 2006 was 8.2 and 7.6 years, respectively.

The aggregate intrinsic value of outstanding and exercisable options at December 31, 2006 was $5,570,678 and $1,524,453, respectively. The intrinsic value is the amount by which the market value of the underlying stock at December 31, 2006 exceeds the exercise price.

F-14

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

The aggregate intrinsic value of stock options exercised during the years 2004, 2005, and 2006 was approximately $98,700, $1,424,568 and $3,250,428, respectively.

GMX received $555,168 in cash for option exercises in 2006. No current tax benefits were realized due to availability of a net operating loss carryforward for tax purposes, but deferred tax liability was reduced by $120,428.

As of December 31, 2006 there was $2,081,805 of total unrecognized compensation costs related to non-vested stock options granted under the Company’s stock option plan. That cost is expected to be recognized over a weighted average period of 3.0 years.

The weighted-average grant-date fair value of options granted during the years 2004, 2005, and 2006 was $3.03, $12.64, and $21.38, respectively.

For the January 2004 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 1%, expected volatility of 116%, and an expected term of four years. For the December 2004 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 1%, expected volatility of 137%, and an expected term of four years.

For the January 2005 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 1%, expected volatility of 132%, and an expected term of four years. For the April 2005 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 1%, expected volatility of 133%, and an expected term of one year.

For the September 2005 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0% risk-free interest rate of 1%, expected volatility of 144%, and an expected term of four years. For the October 2005 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 4%, expected volatility of 140%, and an expected term of four years. For the November 2005 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 4%, expected volatility of 140%, and an expected term of four years.

For the July 2006 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0% risk-free interest rate of 4.98%, expected volatility of 79.8%, and an expected term of four years. For the August 2006 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 4.95%, expected volatility of 79.1%, and an expected term of four years. For the November 2006 options, fair value was determined using the Black Scholes option pricing model with the following assumptions: expected dividend yield of 0%, risk-free interest rate of 4.52%, expected volatility of 77.2%, and an expected term of four years.

F-15

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

COMMITMENTS AND CONTINGENCIES: Liabilities for loss contingencies arising from claims, assessments, litigation, or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Environmental expenditures are expensed or capitalized in accordance with accounting principles generally accepted in the United States of America. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.

RECLASSIFICATION: Certain prior year balances have been reclassified to conform to the current year presentation.

SEGMENT INFORMATION: GMX manages its business by country, which results in one operating segment during each of the years ended December 31, 2004, 2005, and 2006.

ASSET RETIREMENT OBLIGATIONS: Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations.

Balance as of December 31, 2004	$	1,764,631
Liabilities incurred		295,756
Liabilities settled		(474,601	)
Accretion(1)		70,585
Increase due to revisions(2)		555,862
Balance as of December 31, 2005	$	2,212,233
Liabilities incurred		337,160
Liabilities settled		—
Accretion(1)		81,646
Decrease due to revisions(2)		(468,154	)
Balance as of December 31, 2006	$	2,162,885

1	Annual accretion is added to the full cost pool.
2	2005 revisions were due to the increase in market prices for services related to plugging a well, the current inflation rate and interest rate. 2006 revisions were due to a decrease in the current inflation rate and an increase in the current interest rate.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS: The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by the Company to determine the potential impact on its financial statements upon adoption. The Company has concluded that the following new accounting standards are applicable to the Company.

In December 2004, the FASB issued SFAS 123(R),Share-Based Payment, a revision of SFAS 123,Accounting for Stock-Based Compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. We adopted this statement effective January 1, 2006. The effect of SFAS 123(R) is more fully described above under NOTE A—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES-STOCK BASED COMPENSATION.

F-16

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

In July 2006, the FASB issued FASB Interpretation (FIN) No. 48,Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109,Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company does not expect that FIN 48 will have a material impact on its financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. We do not expect that SFAS 157 will have a material impact on our consolidated financial position, results from operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. In addition, it also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of SFAS 157. We do not expect that SFAS 159 will have a material impact on our consolidated financial position, results from operations or cash flows.

F-17

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

NOTE B—PROPERTY AND EQUIPMENT

Property and equipment included the following:

	December 31,
	2005			2006
Oil and gas properties:
Subject to amortization	$	67,130,448		$	173,050,284
Acquisition costs not subject to amortization:
Acquired in 2006		—			597,630
Acquired in 2005		1,255,680			288,262
Acquired in 2004		432,880			238,981
Acquired prior to 2004		101,256			—
		1,789,816			1,124,873
Accumulated depreciation, depletion, and amortization		(9,992,867	)		(16,874,796	)
Net oil and gas properties		58,927,397			157,300,361
Other property and equipment		17,044,734			43,097,326
Less accumulated depreciation		(1,793,781	)		(3,742,057	)
Net other property and equipment		15,250,953			39,355,269
Property and equipment, net of accumulated depreciation, depletion, and amortization	$	74,178,350		$	196,655,630

As of December 31, 2005 and 2006, only certain acquisition costs were not subject to amortization as it is still undetermined whether or not proved reserves can be assigned to such properties. Subject to industry conditions, evaluation of most of these properties, and the inclusion of their costs in the amortized capital costs is expected to be completed within three years. The Company did not have any exploration or development costs subject to amortization at December 31, 2005 or 2006, respectively.

Depreciation, depletion, and amortization of property and equipment consisted of the following components:

	For The Year Ended
	December 31,
	2004		2005		2006
Depreciation, depletion, and amortization of oil and gas properties	$	1,707,431	$	3,496,657	$	6,881,930
Depreciation of other property and equipment		336,054		485,422		1,164,243
Total	$	2,043,485	$	3,982,079	$	8,046,173

F-18

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

NOTE C—LONG-TERM DEBT

	December 31,
	2005		2006
Note payable to bank, maturity date of July 2008 bearing a variable weighted average interest rate of 7.5% and 7.45% as of December 31, 2005 and 2006, respectively, collateralized by oil and gas properties	$	1,000	$	40,000,000
Joint venture partner project (financing, non-recourse, no interest rate)		1,755,002		1,820,283
		1,756,002		41,820,283
Current portion		345,967		251,447
Long Term	$	1,410,035	$	41,568,836

Maturities of long-term debt are as follows:

Year	Amount
2007	$	251,447
2008		40,215,044
2009		171,941
2010		134,803
2011		184,081
2012-2016		584,629
2017-2021		188,005
Thereafter		90,333
	$	41,820,283

Credit Facility

On July 29, 2005, the Company entered into a new secured credit facility (the “Loan Agreement”), which replaced a prior loan agreement. The Loan Agreement has been amended on several occasions since then. The Loan Agreement provides for a line of credit of up to $100,000,000 (the “Commitment”), subject to a borrowing base which is based on a periodic evaluation of oil and gas reserves which is reduced monthly to account for production (“Borrowing Base”). The amount of credit available at any one time under the Loan Agreement is the lesser of the Borrowing Base or the amount of the Commitment. Borrowings bear interest at the prime rate or LIBOR plus 1.50% to 2.25% depending on the level of borrowings relative to the Borrowing Base. The Loan Agreement requires payment of an annual facility fee equal to 1/4% on the unused amount of the Borrowing Base. The Company is obligated to make principal payments if the amount outstanding would exceed the Borrowing Base. Borrowings under the credit agreement are secured by substantially all of the Company’s oil and gas properties. The amount of this Borrowing Base has been adjusted from time to time. At December 31, 2006, the Borrowing Base was $50,000,000 and the Company had $40,000,000 of borrowings under the Loan Agreement. The Loan Agreement matures in July 2008.

The Loan Agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, changes in management and require the maintenance of various financial ratios. As of December 31, 2006, the Company was in compliance with or obtained waivers for all the financial covenants of Loan Agreement.

F-19

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

PVOG Financing

In 2004, GMX entered into an arrangement with PVOG to purchase dollar denominated production payments from the Company on wells drilled with a second rig during a portion of 2004. Under this agreement, PVOG provided to GMX $2.8 million in funding for GMX’s share of costs of four wells drilled with the second rig which is repayable solely from 75% of GMX’s share of production revenues from these wells without interest. As of December 31, 2006, the amount owed under this arrangement was $1,820,283.

NOTE D—INCOME TAXES

Intangible development costs may be capitalized or expensed for income tax reporting purposes, whereas they are capitalized and amortized for financial statement purposes. Lease and well equipment and other property and equipment may be depreciated for income tax reporting purposes using accelerated methods and different lives. Other temporary differences include the effect of hedging transactions and stock based compensation awards. Deferred income taxes are provided on these temporary differences to the extent that income taxes which otherwise would have been payable are reduced. Deferred income tax assets also are recognized for operating losses that are available to offset future income taxes.

At December 31, 2006, the Company had the following carryforwards available to reduce future income taxes:

Net Operating Losses:
Federal	$	27,115,255
Statutory depletion		8,005,037

The net operating loss and statutory depletion carryforward amounts shown above have been utilized for financial purposes to offset existing deferred tax liabilities. The net operating loss carryforwards expire from 2018 to 2021. The Company’s net operating loss has an annual limitation under Internal Revenue Code Section 382. Statutory depletion carryforwards do not expire.

F-20

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

The following table sets forth the Company’s deferred tax assets and liabilities.

	December 31,
	2005			2006
Deferred tax assets:
Net operating loss carry forwards	$	9,272,000		$	9,454,770
Statutory depletion carry forwards		2,274,900			2,721,713
Stock option compensation expense		—			120,428
Total		11,546,900			12,296,911
Deferred tax liabilities:
Property, plant and equipment		(12,759,000	)		(16,924,111	)
Unrealized gain on derivative instrument		—			(399,727	)
Total		(12,759,000	)		(17,323,838	)
Net deferred tax liability	$	(1,212,100	)	$	(5,026,927	)

As of December 31, 2006, a deferred tax liability of $17,323,838 was primarily associated with the difference between financial carrying value of oil and gas properties and the associated tax basis. As of the same date, the Company’s gross deferred tax asset of $12,296,911 was primarily the result of the net operating loss and statutory depletion carryforwards.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable differences over the period which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences as of December 31, 2006.

Total income tax expense for the respective years differed from the amounts computed by applying the U.S. federal tax rate to earnings before income taxes as a result of the following:

	For The Year Ended
	December 31,
	2004			2005			2006
U.S. statutory tax rate		34	%		34	%		34	%
Statutory depletion		(25	)		(12	)		(4	)
Change in valuation allowance		(24	)		(8	)		—
Other		16			—			(2	)
Effective income tax rate		1	%		14	%		28	%

NOTE E—COMMITMENTS AND CONTINGENCIES

The Company is party to various other legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to the Company and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, the Company’s estimates of the outcomes of such matters, and its experience in contesting, litigating, and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to the Company’s financial position or results of operations after consideration of recorded accruals.

F-21

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

OPERATING LEASES: The following is a schedule by year of future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2006.

Year Ending December 31:
2007	$	190,611
2008		170,402
2009		169,124
2010		34,813
Total	$	564,950

Total rental expense for all operating leases is as follows for the years ended December 31:

2004	$	153,613
2005	$	118,701
2006	$	153,589

NOTE F—SHAREHOLDERS’ EQUITY

In October 2000, the board of directors and shareholders adopted the GMX Resources Inc. Stock Option Plan (the “Option Plan”). Under the Option Plan, the Company may grant both stock options intended to qualify as incentive stock options under Section 422 of the Internal Revenue Code and options which are not qualified as incentive stock options. Options may be granted under the Option Plan to key employees and nonemployee directors.

The maximum number of shares of common stock issuable under the Option Plan is 550,000, subject to appropriate adjustment in the event of a reorganization, stock split, stock dividend, reclassification or other change affecting the Company’s common stock. All executive officers and other key employees who hold positions of significant responsibility are eligible to receive awards under the Option Plan. In addition, each director of the Company is eligible to receive options under the Option Plan. The exercise price of options granted under the Option Plan is not less than 100% of the fair market value of the shares on the date of grant. Options granted under the Plan become exercisable as the board may determine in connection with the grant of each option. In addition, the board may at any time accelerate the date that any option granted becomes exercisable. Stock options generally vest over four years and have a 10-year contractual term.

The board of directors may amend or terminate the Option Plan at any time, except that no amendment will become effective without the approval of the shareholders except to the extent such approval may be required by applicable law or by the rules of any securities exchange upon which the Company shares are admitted to listed trading. The Option Plan will terminate in 2010, except with respect to awards then outstanding.

F-22

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

In July 2005, the Company completed a private placement with several institutional investors of 1,600,000 shares on common stock for $21,500,000. Proceeds of the transaction were used for general corporate purposes. The Company’s Class A warrants issued in our initial public offering in 2001 allowed holders to purchase 1,250,000 common shares at $12.00 per share and expired in February 2006. In 2006, prior to the expiration of the warrants, we received approximately $14 million in exercise proceeds and issued an additional 1,164,326 shares of common stock.

In February 2007, the Company completed a public offering of 2,000,000 shares of our common stock for $34.82 per share. Net proceeds to the Company were approximately $65,500,000, which the Company plans to use to fund drilling and development of our East Texas properties and for other general corporate purposes. Pending such uses, a portion of the net proceeds from this offering will be used to reduce indebtedness under our revolving bank credit facility, which will permit additional borrowings in the future under the terms of our bank credit facility.

PREFERRED STOCK: In August 2006, we sold 2,000,000 shares of our 9.25% Series B Cumulative Preferred Stock at $25.00 per share in a public offering, resulting in a total offering size of $50 million. The net proceeds of $47.1 million from the sale of preferred stock was used to fund the drilling and development of the Company’s East Texas properties and for other general corporate purposes.

The initial annual dividend on each share of Series B Cumulative Preferred Stock is $2.3125 (an aggregate of $4,625,000) and is payable quarterly when, as and if declared by the Company, in cash (subject to specified exceptions), in arrears to holders of record as of the dividend payment record date, on or about the last calendar day of each March, June, September and December.

The Series B Cumulative Preferred Stock is not convertible into the Company’s common stock and can be redeemed at the Company’s option after September 30, 2011 at $25.00 per share.  The Series B Cumulative Preferred Stock will be required to be redeemed prior to September 30, 2011 at specified redemption prices and thereafter at $25.00 per share in the event of a change of ownership or control of the Company if the acquirer is not a public company meeting certain financial criteria.

NOTE G—MAJOR CUSTOMERS

Sales to individual customers constituting 10% or more of total oil and gas sales for each of the years ended December 31, 2004, 2005 and 2006 were as follows:

	2004			2005			2006
Various purchasers through Penn Virginia Oil & Gas (Oil)		—			27	%		44	%
Teppco Crude (Oil)		93	%		65	%		48	%
CrossTex Energy Services, Inc. (Gas)		63	%		44	%		42	%
Penn Virginia Oil & Gas (Gas)		21	%		48	%		48	%
Duke Energy (Gas)		10	%		7	%		4	%

F-23

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

NOTE H—CONCENTRATION OF CREDIT RISK

The Company maintains its cash in bank deposit accounts which, at times, may exceed federal insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk.

NOTE I—RETIREMENT PLANS

The GMX Resources Inc. 401(k) Plan was adopted April 15, 2001. The plan is a qualified retirement plan under the Internal Revenue Code. All employees are eligible who have attained age 21. GMX matches the employee contributions dollar for dollar up to 5% of the employees compensation; the Company contributed $87,303, $42,875 and $-0- in 2006, 2005 and 2004, respectively.

NOTE J — HEDGING ACTIVITY

Effective August 1, 2006, the Company entered into a one-year hedging transaction with Union Bank of California for 100,000 MMBtus per month. This transaction is in the form of a fixed-price swap agreement, pursuant to which the Company receives (if the index price is lower than the fixed price) or pays (if the index price is higher than the fixed price) the difference between $8.005 per MMBtu and the index price, which is the Inside FERC – Houston Ship Channel price. The Company entered into this hedge to partially reduce its exposure to natural gas price risk for the period of the hedge. The Company’s commodity price financial swap was designated as a cash flow hedge and was determined to be highly effective at December 31, 2006.

As a result of the Company’s hedging activities, the Company recognized $939,500 of additional oil and gas sales for the year ended December 31, 2006. There were no oil and gas hedging activities in 2005 or 2004. In addition, the fair value of the hedge is $1,175,669 at December 31, 2006.

By using derivative instruments to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are usually placed with counterparties that the Company believes are minimal credit risks.

Market risk is the adverse effect on the value of a derivative instrument that results from a change in interest rates or commodity prices. The market risk associated with commodity price is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

The Company periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through various financial transactions to manage its exposure to oil and gas price volatility. These transactions include financial price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage the Company’s exposure to oil and gas price fluctuations. The oil and gas reference prices upon which these price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

F-24

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

NOTE K—OIL AND GAS OPERATIONS (Unaudited)

Capitalized costs related to the Company’s oil and gas producing activities as of December 31, 2005 and 2006 are:

	2005			2006
Unproved properties	$	1,789,816		$	1,124,873
Producing properties		67,130,448			173,050,284
		68,920,264			174,175,157
Less accumulated depreciation, depletion, and amortization		(9,992,867	)		(16,874,796	)
Net capitalized costs	$	58,927,397		$	157,300,361

Unproved properties include leaseholds under exploration. Producing properties include mineral properties with proved reserves, development wells, and uncompleted development well costs. The accumulated depreciation, depletion, and amortization represent the portion of the assets which has been charged to expense.

Costs incurred in oil and gas property acquisitions, exploration, and development activities in 2004, 2005 and 2006 are as follows:

	2004		2005		2006
Property acquisition costs – unproved	$	851,617	$	1,255,680	$	597,630
Development costs		9,152,257		25,211,613		104,657,264
	$	10,003,874	$	26,467,293	$	105,254,894

Developments costs above for the years ended December 31, 2004, 2005, and 2006 include non-cash asset retirement costs of $1,436,184, $377,017 and $(130,992), respectively. The decrease in non-cash asset retirement costs in 2006 was due to changes in assumptions for inflation and interest rates.

Development costs include the cost of drilling and equipping development wells and constructing related production facilities for extracting, treating, gathering, and storing oil and gas from proved reserves.

The Company’s results of operations in 2004, 2005 and 2006 include revenues and expenses associated directly with oil and gas producing activities.

	2004			2005			2006
Oil and gas sales	$	7,689,882		$	19,026,050		$	31,882,072
Production costs		(1,779,830	)		(3,311,624	)		(4,943,627	)
Depreciation, depletion and amortization		(1,707,431	)		(3,496,657	)		(6,881,930	)
Income tax expense		(1,047,075	)		(1,212,100	)		(3,415,100	)
Results of operations for oil and gas producing activities	$	3,155,546		$	11,005,669		$	16,641,415

F-25

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

NOTE L—SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

The oil and gas reserve quantity information presented below is unaudited and is based upon reports prepared by independent petroleum engineers. The information is presented in accordance with regulations prescribed by the Securities and Exchange Commission. The Company emphasizes that reserve estimates are inherently imprecise. The Company’s reserve estimates were estimated by performance methods, volumetric methods, and comparisons with analogous wells, where applicable. The reserves estimated by the performance method utilized extrapolations of historical production data. Reserves were estimated by the volumetric or analogous methods in cases where the historical production data was insufficient to establish a definitive trend. Accordingly, these estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.

Proved oil and gas reserves represent the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. As of December 31, 2004, 2005 and 2006, all of the Company’s oil and gas reserves were located in the United States.

	OIL			GAS
	(MBBLS)			(MMCF)
December 31, 2004
Proved reserves, beginning of period		1,323			45,029
Extensions, discoveries, and other additions		51			14,644
Production		(30	)		(1,049	)
Revisions of previous estimates		(107	)		(1,736	)
Proved reserves, end of period		1,237			56,888
Proved developed reserves:
Beginning of period		568			18,277
End of period		584			18,980
December 31, 2005
Proved reserves, beginning of period		1,237			56,888
Extensions, discoveries, and other additions		694			84,026
Production		(48	)		(1,930	)
Revisions of previous estimates		88			11,192
Proved reserves, end of period		1,971			150,176
Proved developed reserves:
Beginning of period		584			18,980
End of period		770			41,503
December 31, 2006
Proved reserves, beginning of period		1,971			150,176
Extensions, discoveries, and other additions		831			87,754
Production		(69	)		(3,915	)
Revisions of previous estimates		10			7,926
Proved reserves, end of period		2,743			241,941
Proved developed reserves:
Beginning of period		770			41,503
End of period		947			70,801

F-26

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

The increase in proved reserves from extensions, discoveries, and other additions is the direct result of additional drilling on the Company’s acreage in East Texas, specifically the exploitation of the Cotton Valley formation. Over the past several years as the Company has drilled Cotton Valley wells, additional offsets have been proved (using SEC definitions of offset as only withinone spacing unit of any existing producer or test).

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax bases of the properties and related carryforwards giving effect to permanent differences. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board, and, as such do not necessarily reflect the Company’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in Statement of Financial Accounting Standards No. 69.

	December 31,			December 31,			December 31,
	2004			2005			2006
	(In thousands)			(In thousands)			(In thousands)
Future cash inflows	$	375,427		$	1,648,402		$	1,577,259
Future production costs		(94,338	)		(373,614	)		(560,094	)
Future development costs		(66,811	)		(190,700	)		(309,907	)
Future income tax provisions		(48,926	)		(283,784	)		(178,258	)
Net future cash inflows		165,352			800,304			529,000
Less effect of a 10% discount factor		(101,121	)		(497,908	)		(332,985	)
Standardized measure of discounted future net cash flows	$	64,231		$	302,396		$	196,015

Oil and condensate prices were based on an equivalent base price of $43.45, $61.04 and $61.05 per barrel for benchmark posted West Texas Intermediate Crude Oil at closing on December 31, 2004, 2005, and 2006, respectively. Adjustments to the base price were made to each lease to adjust the base price for crude oil quality, contractual agreements, and regional price variations. The average oil price used in the reserve estimates was $42.02, $57.19 and $58.89 per barrel at December 31, 2004, 2005, and 2006, respectively. Natural gas prices were based on an equivalent base price of $6.15, $11.23 and $6.29 per million British thermal unit (mmbtu) for the composite Henry Hub Spot Market benchmark price at closing on December 31, 2004, 2005, and 2006, respectively. Adjustments to the base price were made to each lease to adjust the base price for quality, contractual agreements, and regional price variations. The average natural gas price used in the reserve estimates was $5.69, $10.23 and $5.85 per mmbtu at December 31, 2004, 2005, and 2006, respectively. Future income tax expenses are computed by applying the appropriate statutory rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved giving effect to permanent differences, tax credits, and allowances relating to proved oil and gas reserves.

F-27

GMX Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2004, 2005 and 2006

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

	December 31,			December 31,			December 31,
	2004			2005			2006
	(In thousands)			(In thousands)			(In thousands)
Standardized measure, beginning of year	$	47,975		$	64,231		$	302,396
Sales of oil and gas, net of production costs		(5,910	)		(15,714	)		(26,938	)
Net changes in prices and production costs		4,409			49,869			(214,311	)
Change in estimated future development costs		—			—			(43,753	)
Extensions and discoveries, net of future development costs		18,949			223,384			93,427
Development costs that reduced future development costs		6,863			23,629			104,707
Revisions of quantity estimates		(4,035	)		26,174			17,399
Sales of reserves in place		—			—			—
Accretion of discount		1,149			97,164			40,962
Changes in timing of production and other		(9,379	)		(78,118	)		(116,976	)
Net changes in income taxes		4,210			(88,223	)		39,102
Standardized measure, end of year	$	64,231		$	302,396		$	196,015

F-28

NOTE M—QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized unaudited quarterly financial data for 2005 and 2006 are as follows:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
2006
Revenues	$	6,715,890	$	6,493,516	$	8,534,070	$	10,289,212	$	32,032,688
Income before income taxes		2,779,804		1,942,117		3,904,805		3,763,242		12,389,968
Net income		2,134,327		1,592,494		2,860,905		2,387,142		8,974,868
Net income applicable to common stock		2,134,327		1,592,494		2,218,545		1,230,892		7,176,258
Basic earnings per share1		0.20		0.14		0.20		0.11		0.65
Diluted earnings per share1		0.19		0.14		0.19		0.11		0.64
2005
Revenues	$	2,617,680	$	3,455,375	$	4,375,657	$	8,743,992	$	19,192,704
Income before income taxes		604,524		914,864		2,050,332		4,798,476		8,368,196
Net income		604,524		914,864		2,050,332		3,586,376		7,156,096
Net income applicable to common stock		604,524		914,864		2,050,332		3,586,376		7,156,096
Basic earnings per share1		0.07		0.11		0.20		0.35		0.81
Diluted earnings per share1		0.07		0.11		0.20		0.33		0.79

¹ The sum of the per share amounts per quarter does not equal the year due to the changes in the average number of common shares outstanding

NOTE N — SUBSEQUENT EVENT – COMMON STOCK OFFERING

On February 7, 2007, the Company sold 2 million shares of common stock. The net proceeds to the Company were approximately $65.5 million. The Company expects to use the net proceeds to fund drilling and development of its East Texas properties and for other general corporate purposes. Pending such uses, a portion of the net proceeds were used to reduce indebtedness under the Company’s revolving bank credit facility to zero, which will permit additional borrowings in the future under the terms of the credit facility.

F-29

EXHIBIT INDEX

Exhibit No.	Description
3.1	Amended and Restated Certificate of Incorporation of GMX Resources Inc. (Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form SB-2, File No. 333-49328)
3.2	Amended Bylaws of GMX Resources Inc. (Incorporated by reference to Exhibit 3.2 to Annual Report onForm 10-QSB for the quarter ended September 30, 2004)
3.3	Certificate of Designation of Series A Junior Participating Preferred Stock of GMX Resources Inc. dated May 17, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed May 18, 2005)
3.4	Certificate of Designation of 9.25% Series B Cumulative Preferred Stock (incorporated by reference to Exhibit 4.1 to Form 8-A12B filed on August 8, 2006)
4.4	Rights Agreement dated May 17, 2005 by and between GMX Resources Inc. and UMB Bank, N.A., as Rights Agent (Incorporated by reference to Exhibit 4.1 to Form 8-K filed May 18, 2005)
10.1	Stock Option Plan, as amended (Incorporated by reference to Exhibit 10.2 to the Registration Statement on Form SB-2, File No. 333-49328)
10.2	Form of Director Indemnification Agreement (Incorporated by reference to Exhibit 10.5 to the Registration Statement on Form SB-2, File No. 333-49328)
10.3	Participation Agreement dated December 29, 2003 by and among Penn Virginia Oil & Gas Company, the Company and its wholly owned subsidiaries (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K dated December 29, 2003)
10.3(a)	First Amendment dated February 27, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed September 14, 2004)
10.3(b)	Second Amendment dated May 9, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed September 14, 2004)

Exhibit No.	Description
10.3(c)	Third Amendment dated April 6, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed September 14, 2004)
10.3(d)	Fourth Amendment dated August 11, 2004 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K filed September 14, 2004)
10.3(e)	Fifth Amendment dated effective January 1, 2005 to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas L.P., successor to Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.6(e) to Quarterly Report on Form 10-QSB for the quarter ended March 31, 2005, filed May 12, 2005)
10.3(f)	Sixth Amendment dated effective January 1, 2006, to Participation Agreement between GMX Resources Inc. and Penn Virginia Oil & Gas L.P., successor to Penn Virginia Oil & Gas Corporation (Incorporated by reference to Exhibit 10.1 to Form 8-K filed January 20, 2006)
10.4	Amended and Restated Loan Agreement dated June 7, 2006 between GMX Resources Inc., Capital One, National Association, and Union Bank of California, N.A.. (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on June 9, 2006)
10.4(a)	Amended and Restated Texas Deed of Trust, Mortgage, Assignment, Security Agreement, Fixture Filing and Financing Statement dated as of June 7, 2006 from GMX Resources Inc. to Capital One, National Association, as Agent (Incorporated by reference to Exhibit 10.2 to Current report on Form 8-K filed June 9, 2006)
10.4(b)	Security Agreement (Stock) dated June 7, 2006 between GMX Resources Inc. and Capital One, National Association (Incorporated by reference to Exhibit 10.3 to Current report on Form 8-K filed June 9, 2006)
10.4(c)	Security Agreement (Promissory Note) dated June 7, 2006 between GMX Resources Inc. and Capital One, National Association (Incorporated by reference to Exhibit 10.4 to Current report on Form 8-K filed June 9, 2006)
10.4(d)	Security Agreement dated June 7, 2006 between Endeavor Pipeline, Inc. and Capital One, National Association (Incorporated by reference to Exhibit 10.5 to Current report on Form 8-K filed June 9, 2006)
10.4(e)	First Amendment to Loan Agreement dated August 4, 2006, between GMX Resources Inc., Capital One, National Association and Union Bank of California, N.A. (Incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed August 7, 2006)
10.5	Asset Purchase Agreement dated December 8, 2005 between GMX Resources Inc. and McLachlan Drilling Co. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed December 12, 2005)
14	Code of Business Conduct and Ethics (Incorporated by reference to Exhibit 14 to Annual Report on Form 10-KSB for the year ended December 31, 2003)

Exhibit No.	Description
21	List of Subsidiaries (Incorporated by reference to Exhibit 21 to Annual Report on Form 10-KSB for the year ended December 31, 2005)
23.1	Consent of Independent Accountants
23.2	Consent of MHA Petroleum Consultants
23.3	Consent of Sproule Associates, Inc.
31.1	Rule 13a-14(a) Certification of Chief Executive Officer
31.2	Rule 13a-14(a) Certification of Chief Financial Officer
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350.