WWW.EXFILE.COM, INC. -- 14956 -- GMX RESOURCES, INC. -- FORM 10-K

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10-K 1 form10-k_14956.htm GMX RESOURCES, INC. FORM 10-K WWW.EXFILE.COM, INC. -- 14956 -- GMX RESOURCES, INC. -- FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

T	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 000-32325

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

(Address of principal executive offices)

73114

(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. Yes £ No T

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T

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

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

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 filer £

Accelerated filer T

Non-accelerated file £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act) Yes £ No T

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.

GMX RESOURCES INC.

Form 10-K

Table of Contents

		Page
PART I		1

Item 1.	Business	1
	General	1
	2006 and 2007 Developments	1
	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	25
	Productive Well Summary	25
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

	Purchases of Equity Securities	28
Item 6.	Selected Financial Data.	29
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	36
	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 Arranagements	39
	Price Risk Management	39
	Forward-Looking Statements	39
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

PART I

Item1.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 450 Fifth Street, N.W. 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.

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.

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.

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.

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.

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.

Estimating our reserves and future net cash flows is difficult to do with any certainty.

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.

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;

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.

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.

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

	East Texas and Louisiana		Southeast New Mexico		Total
Property Statistics:
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.

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.

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.

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 Revenues ($000s)	$	214,278	$	1,648,402	$	1,577,259

Present Value ¹($000s)	$	83,237	$	409,624	$	262,066

Standardized Measure ¹ ($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.}

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.

	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.

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.

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.

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:

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.

	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	)		—