**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
  **Commissi** **on
          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, LLCSeries
                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 accelera t ed
      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
                filerT
            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**


PagePART
                  I
              
              1Item
                  1.
              Business
              1General
              12006
                  and 2007 Developments
              1Business
                  Strategy
              22007
                  Plans
              3Marketing
              3Regulation
              4Gas
                  Gathering
              7Competition
              7Facilities
              8Employees
              8Certain
                  Technical Terms
              8Availability
                  of Information
              11Item
                  1A.
              Risk
                  Factors.
              12Risks
                  Related to GMX
              12Risks
                  Related to the Oil and Gas Industry
              15Item
                  1B.
              Unresolved
                  Staff Comments.
              19Item
                  2.
              Properties.
              19General
              19East
                  Texas
              20Northwestern
                  Louisiana
              22Southeast
                  New Mexico
              23Reserves
              23Costs
                  Incurred
              24Drilling
                  Results
              25Acreage
              25Productive
                  Well Summary
              25Item
                  3.
              Legal
                  Proceedings.
              26Item
                  4.
              Submission
                  of Matters to a Vote of Security Holders.
              26PART
                  II
              
              27Item
                  5.
              Market
                  for Registrant’s Common Equity, Related Stockholder Matters and Issuer
                  Purchases of Equity Securities.
              27Common
                  Stock
              27Equity
                  Compensation Plan Information
              27Shareholder
                  Return Performance Graph
              28Recent
                  Sales of Unregistered Securities
              28
  i
 Purchases
                  of Equity Securities
              28Item
                  6.
              Selected
                  Financial Data.
              29Item
                  7.
              Management’s
                  Discussion and Analysis of Financial Condition and Results of
                  Operation.
              30Summary
                  Operating and Reserve Data
              30Critical
                  Accounting Policies
              31Results
                  of Operations for the Year Ended December 31, 2006 Compared to the
                  Year Ended December 31, 2005
              34Results
                  of Operations for the Year Ended December 31, 2005 Compared to
                  the Year
                  Ended December 31, 2004
              35Capital
                  Resources and Liquidity
              36Credit
                  Facility
              36Other
                  Financing - 2006 and 2007
              38Working
                  Capital
              38Commitments
                  and Capital Expenditures
              38Liquidity
                  and Financing Considerations
              392007
                  Guidance
              39Recently
                  Issued Accounting Pronouncements
              39Off-Balance
                  Sheet Arranagements
              39Price
                  Risk Management
              39Forward-Looking
                  Statements
              39Item
                  7A.
              Quantitative
                  and Qualitative Disclosures About Market Risk.
              40Item
                  8.
              Financial
                  Statements and Supplementary Data.
              41Item
                  9.
              Changes
                  in and Disagreements With Accountants on Accounting and Financial
                  Disclosure
              41Item
                  9A.
              Controls
                  and Procedures
              41Controls
                  and Procedures
              41Changes
                  in Internal Control Over Financial Reporting
              42Management’s
                  Annual Report on Internal Control over Financial Reporting
              42Certifications
              42Item
                  9B.
              Other
                  Information.
              42PART
                  III
              
              43PART
                  IV
              
              44Item
                  15.
              Exhibits
                  and Financial Statement Schedules.
              44




ii


**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


1


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




2


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


3


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.


4


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


5


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.




6


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,


7


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 c ubic
      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.


8


*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.




9


*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


10


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




11


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


12


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.


13


*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




14


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;




15


·
              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,




16


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;




17


·
              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.




18


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 comp etitors
      have substantially greater financial and other resources than we have. In
      addition, larger competi tors
      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.**




No n e.




**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.




19


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
            
            
            258,403Percent
                of total proved reserves
            
            
            99%
            
            
            1%
            
            
            100%Gross
                producing wells
            
            
            155
            
            
            9
            
            
            164Net
                producing wells
            
            
            90.1
            
            
            5.7
            
            
            95.8Gross
                acreage
            
            
            31,737
            
            
            1,920
            
            
            33,657Net
                acreage
            
            
            17,786
            
            
            1,458
            
            
            19,244Proved
                developed reserves (MMcfe)
            
            
            75,181
            
            
            1,302
            
            
            76,483Proved
                undeveloped reserves (MMcfe)
            
            
            181,130
            
            
            790
            
            
            181,920Estimated
                total future development costs ($000s)
            
            
            308,951
            
            
            956
            
            
            309,907Estimated
                2007 development costs ($000s)
            
            
            145,000
            
            
            0
            
            
            145,000Proved
                undeveloped locations
            
            
            274
            
            
            1
            
            
            275**Year
                ended December 31, 2006 results:**Production
                (net MMcfe)
            
            
            4,166
            
            
            161
            
            
            4,327Average
                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
      interest s 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




20


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
      participatio n 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




21


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.




22


**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
            
            
            70,801Oil
                (MBbls)
            
            
            584
            
            
            770
            
            
            947Total
                (MMcfe)
            
            
            22,484
            
            
            46,123
            
            
            76,484**Proved
                Undeveloped**:Gas
                (MMcf)
            
            
            37,908
            
            
            108,673
            
            
            171,140Oil
                (MBbls)
            
            
            653
            
            
            1,201
            
            
            1,797Total
                (MMcfe)
            
            
            41,826
            
            
            115,880
            
            
            181,920**Total
                Proved**:Gas
                (MMcf)
            
            
            56,888
            
            
            150,176
            
            
            241,941Oil
                (MBbls)
            
            
            1,237
            
            
            1,971
            
            
            2,744Total
                (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**




23


**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
            
            
            104,657,264Total
            
            $
            10,003,874
            
            $
            26,467,293
            
            $
            105,254,894





24


**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
            
            NetGas
            
            
            15
            
            
            4
            
            
            31
            
            
            16
            
            
            67
            
            
            35.3Oil
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            —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
            
            
            4,084Southeast
                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 o f
      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
            
            
            80.4Oil
            
            
            20
            
            
            15.4Total
            
            
            164
            
            
            95.8





25


**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.




26


**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
            
            $
            6.22Second
                Quarter
            
            
            14.69
            
            
            9.53Third
                Quarter
            
            
            27.00
            
            
            13.69Fourth
                Quarter
            
            
            42.27
            
            
            20.66**Year
                Ended December 31, 2006**First
                Quarter
            
            $
            50.50
            
            $
            28.65Second
                Quarter
            
            
            47.00
            
            
            25.17Third
                Quarter
            
            
            35.12
            
            
            25.40Fourth
                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 f orth
      information as of December 31, 2006 relating to equity compensation
      plans.







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





27


**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.




28


**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
            
            $
            31,882,072Interest
                and other income
            
            
            17,550
            
            
            21,424
            
            
            143,828
            
            
            166,654
            
            
            150,616Total
                revenues
            
            
            5,988,342
            
            
            5,388,794
            
            
            7,833,710
            
            
            19,192,704
            
            
            32,032,688Lease
                operations
            
            
            1,324,481
            
            
            850,034
            
            
            1,261,109
            
            
            2,070,286
            
            
            4,478,805Production
                and severance taxes
            
            
            382,825
            
            
            384,069
            
            
            518,721
            
            
            1,241,338
            
            
            464,822General
                and administrative
            
            
            2,577,388
            
            
            1,578,865
            
            
            1,985,912
            
            
            3,388,396
            
            
            5,828,865Depreciation,
                depletion andamortization
            
            
            1,901,976
            
            
            1,549,678
            
            
            2,043,485
            
            
            3,982,079
            
            
            8,046,173Interest
            
            
            510,472
            
            
            439,313
            
            
            558,504
            
            
            142,409
            
            
            824,055Total
                expenses
            
            
            6,697,142
            
            
            4,801,959
            
            
            6,367,731
            
            
            10,824,508
            
            
            19,642,720Income
                (loss) before income taxes
            
            
            (708,800
            )
            
            586,835
            
            
            1,465,979
            
            
            8,368,196
            
            
            12,389,968Income
                tax expense - current
            
            
            (263,000
            )
            
            —
            
            
            24,206
            
            
            —
            
            
            —Income
                tax expense - deferred
            
            
            —
            
            
            —
            
            
            —
            
            
            1,212,100
            
            
            3,415,100Net
                income before cumulative effectof
                a change in accounting principle
            
            
            (445,800
            )
            
            586,835
            
            
            1,441,773
            
            
            7,156,096
            
            
            8,974,868Cumulative
                effect of a change inaccounting
                principle
            
            
            —
            
            
            (51,834
            )
            
            —
            
            
            —
            
            
            —Preferred
                stock dividends
            
            
            —
            
            
            —
            
            
            —
            
            
            —
            
            
            1,798,610Net
                income (loss) applicable tocommon
                stock
            
            $
            (445,800
            )
            $
            535,001
            
            $
            1,441,773
            
            $
            7,156,096
            
            $
            7,176,258Net
                income (loss) per share - beforecumulative
                effect
            
            $
            (.07
            )
            $
            .09
            
            $
            .19
            
            $
            .81
            
            $
            .65Cumulative
                effect
            
            
            —
            
            
            (.01
            )
            
            —
            
            
            —
            
            
            —Net
                income (loss) per share -basic
            
            $
            (.07
            )
            $
            .08
            
            $
            .19
            
            $
            .81
            
            $
            .65Net
                income (loss) per share - diluted
            
            $
            (.07
            )
            $
            .08
            
            $
            .19
            
            $
            .79
            
            $
            .64Weighted
                average common shares - basic
            
            
            6,550,000
            
            
            6,560,000
            
            
            7,396,880
            
            
            8,797,529
            
            
            11,120,204Weighted
                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) operatingactivities
            
            $
            (2,547,639
            )
            $
            1,014,290
            
            $
            3,684,155
            
            $
            16,323,103
            
            
            38,333,076Cash
                provided by (used in) investingactivities
            
            
            1,267,831
            
            
            464,315
            
            
            (8,877,944
            )
            
            (39,549,002
            )
            
            (130,572,799
            )Cash
                provided by (used in) financingactivities
            
            
            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
            
            $
            157,300,361Total
                assets
            
            
            33,319,432
            
            
            31,501,206
            
            
            40,991,463
            
            
            81,103,271
            
            
            210,322,523Long-term
                debt, including current portion
            
            
            8,100,000
            
            
            6,690,000
            
            
            3,762,294
            
            
            1,756,002
            
            
            41,820,283Shareholders’
                equity
            
            
            21,607,463
            
            
            22,618,565
            
            
            32,406,856
            
            
            61,225,096
            
            
            131,480,942


29


**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
            
            
            69Natural
                gas (MMcf)
            
            
            1,639
            
            
            917
            
            
            1,049
            
            
            1,930
            
            
            3,915Gas
                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
            
            $
            63.22Natural
                gas (per Mcf)(2)
            
            
            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
            
            $
            1.04Production
                and severance taxes(3)
            
            
            .19
            
            
            .34
            
            
            .42
            
            
            .56
            
            
            .11General
                and administrative
            
            
            1.25
            
            
            1.40
            
            
            1.61
            
            
            1.53
            
            
            1.35Total
            
            $
            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
            
            
            241.9Oil
                (MMbls)
            
            
            1.7
            
            
            1.3
            
            
            1.2
            
            
            2.0
            
            
            2.7Total
                (Bcfe)
            
            
            66.7
            
            
            53.0
            
            
            64.3
            
            
            162.0
            
            
            258.4Estimated
                Future Net Revenues ($MM)(4)(5)
            
            $
            486.3
            
            $
            178.3
            
            $
            214.3
            
            $
            1,648.9
            
            $
            1,557.3Present
                Value ($MM)(3)(4)
            
            $
            80.6
            
            $
            71.2
            
            $
            83.2
            
            $
            409.6
            
            $
            262.1Standardized
                measure of discounted future net cash flows ($MM)(6)
            
            $
            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.”
  30


**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.




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.




31


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.




32


*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.




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.




33


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, 200** **5**




*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.




*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.




34


*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.




*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




35


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.




**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




36


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;




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




37


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****Contractual
                Obligations**
            
            **Total**
            
            **Less
                than 1 year**
            
            **1-3
                years**
            
            **3-5
                years**
            
            **More
                than 5 years**Long-term
                debt
            
            $
            40,000,000
            
            $
            —
            
            $
            40,000,000
            
            $
            —
            
            $
            —Operating
                leases
            
            
            564,950
            
            
            190,611
            
            
            339,526
            
            
            34,813
            
            
            —75%
                PVOG Financing 1
            
            
            1,820,283
            
            
            251,447
            
            
            386,985
            
            
            318,884
            
            
            862,967Total
            
            $
            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.




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
  38
 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 Arranagements**




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.




**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,”




39


“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 f inancial
      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:




**Effective
                Date**
            **Maturity
                Date**
            
            **Notional
                Amount Per Month (MMBtu)**
            
            **Remaining
                Notional Amount as of December 31, 2006 (MMBtu)**
            
            **Fixed
                Price per MMBtu**8/1/2006
            7/31/2007
            
            100,000
            
            700,000
            
            $8.0052/1/2007
            12/31/2008
            
            200,000
            
            4,600,000
            
            $7.4608/1/2007
            12/31/2008
            
            100,000
            
            1,700,000
            
            $7.600





40


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.




42


**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.















44


**SIGNATURES**




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




*GMX
              RESOURCES
              INC.*Dated:
                March 15, 2007
            By:
            /s/ Ken
              L.
              Kenworthy, Jr.Ken
                L. Kenworthy, Jr., President




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





**Signatures**
            
            **Title**
            
            **Date**/s/
                Ken L. Kenworthy, Jr.
              Ken
                L. Kenworthy, Jr.
            
            President
                and Director
              (Principal
                Executive Officer)
            
            March
                15, 2007/s/
                Ken L. Kenworthy, Sr.
              Ken
                L. Kenworthy, Sr.
            
            Executive
                Vice President, Chief Financial Officer and Director (Principal Financial
                and Accounting Officer)
            
            March
                15, 2007/s/
                T. J. Boismier
              T.
                J. Boismier
            
            Director
            
            March
                15, 2007/s/
                Steven Craig
              Steven
                Craig
            
            Director
            
            March
                15, 2007/s/
                Jon W. McHugh
              Jon
                W. McHugh
            
            Director
            
            March
                15, 2007





45
 
 **INDEX
          TO CONSOLIDATED FINANCIAL STATEMENTS**
    Report
                    of Independent Registered Public Accounting Firm
                F-2Management’s
                    Annual Report on Internal Control over Financial Reporting
                F-4Consolidated
                    Balance Sheets, December 31, 2005 and 2006
                F-5Consolidated
                    Statements of Operations, Years Ended December 31, 2004, 2005
                    and
                    2006
                F-6Consolidated
                    Statements of Changes in Shareholders' Equity, Years Ended December
                    31,
                    2004, 2005 and 2006
                F-7Consolidated
                    Statements of Cash Flows, Years Ended December 31, 2004, 2005
                    and
                    2006
                F-8Consolidated
                    Statements of Comprehensive Income, Years Ended December 31,
                    2004, 2005
                    and 2006
                F-9Notes
                    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 of *GMX
          Resources Inc* . *and
          Subsidiaries* as 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, that *GMX
          Resources Inc. and Subsidiaries* maintained effective internal control over financial reporting as of December
          31, 2006, based on criteria established in *Internal
          Control-Integrated Framework* issued
          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.
  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
  F-2
 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 respect, the financial position of *GMX
          Resources Inc. and Subsidiaries* as 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 that *GMX
          Resources Inc. and Subsidiaries* maintained effective internal control over financial reporting as of
          December 31, 2006, is fairly stated, in all material respects, based on
          criteria established in *Internal
          Control-Integrated Framework* issued
          by the Committee of Sponsoring Organizations of the Treadway Commission
          (COSO).
          Furthermore, in our opinion, *GMX
          Resources Inc. and Subsidiaries* maintained, in all material respects, effective internal control over financial
          reporting as of December 31, 2006, based on criteria established in *Internal
          Control-Integrated Framework* issued
          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 in *Internal
          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 in *Internal
          Control-Integrated Framework* issued
          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,****ASSETS**
                
                **2005**
                
                **2006**CURRENT
                    ASSETS:Cash
                    and cash equivalents
                
                $
                2,392,497
                
                $
                4,959,749Accounts
                    receivable—interest owners
                
                
                74,971
                
                
                64,185Accounts
                    receivable—oil and gas revenues
                
                
                4,188,451
                
                
                5,766,286Derivative
                    instruments
                
                
                —
                
                
                1,175,669Inventories
                
                
                247,364
                
                
                373,420Prepaid
                    expenses and deposits
                
                
                10,028
                
                
                1,284,904Total
                    current assets
                
                
                6,913,311
                
                
                13,624,213OIL
                      AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD
                      OFACCOUNTING
                
                
                68,920,264
                
                
                174,175,157Less
                    accumulated depreciation, depletion, and amortization
                
                
                (9,992,867
                )
                
                (16,874,796
                )58,927,397
                
                
                157,300,361OTHER
                    PROPERTY AND EQUIPMENT
                
                
                17,044,734
                
                
                43,097,326Less
                    accumulated depreciation
                
                
                (1,793,781
                )
                
                (3,742,057
                )15,250,953
                
                
                39,355,269OTHER
                    ASSETS
                
                
                11,610
                
                
                42,680TOTAL
                    ASSETS
                
                $
                81,103,271
                
                $
                210,322,523**LIABILITIES
                    AND SHAREHOLDERS’ EQUITY**CURRENT
                    LIABILITIES:Accounts
                    payable
                
                $
                7,809,387
                
                $
                24,658,305Accrued
                    expenses
                
                
                419,130
                
                
                3,236,536Accrued
                    interest
                
                
                25,430
                
                
                314,181Revenue
                    distributions payable
                
                
                317,232
                
                
                513,416Short-term
                    loan
                
                
                5,100,000
                
                
                —Current
                    portion of long-term debt
                
                
                345,967
                
                
                251,447Total
                    current liabilities
                
                
                14,017,146
                
                
                28,973,885LONG-TERM
                    DEBT, LESS CURRENT PORTION
                
                
                1,410,035
                
                
                41,568,836OTHER
                    LIABILITIES
                
                
                3,238,894
                
                
                3,271,933DEFERRED
                    INCOME TAXES
                
                
                1,212,100
                
                
                5,026,927SHAREHOLDERS’
                    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)
                
                
                —
                
                
                2,000Common
                    stock, par value $.001 per share-authorized 50,000,000 sharesissued
                  and
                    outstanding 9,975,315 shares in 2005 and 11,242,136 shares in
                    2006
                
                
                9,975
                
                
                11,242Additional
                    paid-in capital
                
                
                50,965,235
                
                
                113,265,614Retained
                    earnings
                
                
                10,249,886
                
                
                17,426,144Other
                    comprehensive income
                
                
                —
                
                
                775,942Total
                    shareholders’ equity
                
                
                61,225,096
                
                
                131,480,942TOTAL
                    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
                
                $
                31,882,072Interest
                    income
                
                
                14,498
                
                
                161,434
                
                
                150,285Other
                    income
                
                
                129,330
                
                
                5,220
                
                
                331Total
                    revenue
                
                
                7,833,710
                
                
                19,192,704
                
                
                32,032,688EXPENSES:Lease
                    operations
                
                
                1,261,109
                
                
                2,070,286
                
                
                4,478,805Production
                    and severance taxes
                
                
                518,721
                
                
                1,241,338
                
                
                464,822Depreciation,
                    depletion and amortization
                
                
                2,043,485
                
                
                3,982,079
                
                
                8,046,173Interest
                
                
                558,504
                
                
                142,409
                
                
                824,055General
                    and administrative
                
                
                1,985,912
                
                
                3,388,396
                
                
                5,828,865Total
                    expenses
                
                
                6,367,731
                
                
                10,824,508
                
                
                19,642,720Income
                    before income taxes
                
                
                1,465,979
                
                
                8,368,196
                
                
                12,389,968INCOME
                    TAXES
                
                
                24,206
                
                
                1,212,100
                
                
                3,415,100NET
                    INCOME
                
                
                1,441,773
                
                
                7,156,096
                
                
                8,974,868Preferred
                    stock dividends
                
                
                —
                
                
                —
                
                
                1,798,610NET
                    INCOME APPLICABLE TO COMMON STOCK
                
                $
                1,441,773
                
                $
                7,156,096
                
                $
                7,176,258Earnings
                    per share - Basic
                
                $
                0.19
                
                $
                0.81
                
                $
                0.65Earnings
                    per share -Diluted
                
                $
                0.19
                
                $
                0.79
                
                $
                0.64Weighted
                    average common shares-Basic
                
                
                7,396,880
                
                
                8,797,529
                
                
                11,120,204Weighted
                    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**
   **Preferred**
                  **shares**
                ****
                **Common**
                  **shares**
                ****
                **Preferred**
                  **par
                    value**
                ****
                **Common**
                  **par
                    value**
                ****
                **Additional**
                  **paid-in**
                  **capital**
                ****
                **Retained**
                  **earnings**
                ****
                **Other**
                  **compre-**
                  **hensive**
                  **income**
                ****
                **Total**
                  **shareholders’**
                  **equity**BALANCE
                    AT DECEMBER 31, 2003
                
                
                —
                
                
                6,575,000
                
                $
                —
                
                $
                6,575
                
                $
                20,959,973
                
                $
                1,652,017
                
                $
                —
                
                $
                22,618,565Options
                    Exercised
                
                
                —
                
                
                15,000
                
                
                —
                
                
                15
                
                
                14,985
                
                
                —
                
                
                —
                
                
                15,000Redeemed
                    & CancelledWarrants
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (118,712
                )
                
                —
                
                
                —
                
                
                (118,712
                )Warrants
                    Granted
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                257,250
                
                
                —
                
                
                —
                
                
                257,250Warrants
                    Exercised
                
                
                —
                
                
                163,540
                
                
                —
                
                
                164
                
                
                177,398
                
                
                —
                
                
                —
                
                
                177,562Shares
                    Issued
                
                
                —
                
                
                1,300,000
                
                
                —
                
                
                1,300
                
                
                8,014,118
                
                
                —
                
                
                —
                
                
                8,015,418Net
                    income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                1,441,773
                
                
                —
                
                
                1,441,773BALANCE
                    AT DECEMBER 31, 2004
                
                
                —
                
                
                8,053,540
                
                $
                —
                
                $
                8,054
                
                $
                29,305,012
                
                $
                3,093,790
                
                $
                —
                
                $
                32,406,856Options
                    Exercised
                
                
                —
                
                
                128,250
                
                
                —
                
                
                128
                
                
                422,787
                
                
                —
                
                
                —
                
                
                422,915Redeemed
                    & CancelledWarrants
                
                
                —
                
                
                (144,180
                )
                
                —
                
                
                (144
                )
                
                (774,134
                )
                
                —
                
                
                —
                
                
                (774,278
                )Warrants
                    Granted
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                ---Warrants
                    Exercised
                
                
                —
                
                
                337,705
                
                
                —
                
                
                337
                
                
                1,666,898
                
                
                —
                
                
                —
                
                
                1,667,235Shares
                    Issued
                
                
                —
                
                
                1,600,000
                
                
                —
                
                
                1,600
                
                
                20,344,672
                
                
                —
                
                
                —
                
                
                20,346,272Net
                    Income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                7,156,096
                
                
                —
                
                
                7,156,096BALANCE
                    AT DECEMBER 31, 2005
                
                
                —
                
                
                9,975,315
                
                $
                —
                
                $
                9,975
                
                $
                50,965,235
                
                $
                10,249,886
                
                $
                —
                
                $
                61,225,096Stock
                    Options Exercised
                
                
                —
                
                
                102,500
                
                
                —
                
                
                103
                
                
                555,065
                
                
                —
                
                
                —
                
                
                555,168Warrants
                    Exercised
                
                
                —
                
                
                1,164,321
                
                
                —
                
                
                1,164
                
                
                13,971,776
                
                
                —
                
                
                —
                
                
                13,972,940Stock
                    Option CompensationExpense
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                662,341
                
                
                —
                
                
                —
                
                
                662,341Series
                    B Preferred SharesIssued
                
                
                2,000,000
                
                
                —
                
                
                2,000
                
                
                —
                
                
                47,111,197
                
                
                —
                
                
                —
                
                
                47,113,197Preferred
                    Stock Dividends
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                (1,798,610
                )
                
                —
                
                
                (1,798,610
                )Unrealized
                    Gain onDerivative
                    Instruments
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                775,942
                
                
                775,942Net
                    Income
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                —
                
                
                8,974,868
                
                
                —
                
                
                8,974,868BALANCE
                    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 ACTIVITIESNet
                    income
                
                $
                1,441,773
                
                $
                7,156,096
                
                $
                8,974,868Adjustments
                      to reconcile net incometo net cash provided by operating
                      activities;Depreciation,
                    depletion, and amortization
                
                
                2,043,485
                
                
                3,982,080
                
                
                8,046,173Amortization
                    of loan fees
                
                
                326,762
                
                
                112,349
                
                
                29,610Deferred
                    income taxes
                
                
                —
                
                
                1,212,100
                
                
                3,415,100Non
                    cash stock compensation expense
                
                
                —
                
                
                —
                
                
                662,341Net
                    cash provided by operating activities before working capital
                    changes
                
                
                3,812,020
                
                
                12,462,625
                
                
                21,128,092Decrease
                    (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
                
                
                16,848,918Accrued
                    expenses and other liabilities
                
                
                40,128
                
                
                309,842
                
                
                3,106,157Revenue
                    distributions payable
                
                
                (58,067
                )
                
                742,446
                
                
                278,571Net
                    cash provided by operating activities
                
                
                3,684,155
                
                
                16,323,103
                
                
                38,333,076CASH
                    FLOWS DUE TO INVESTING ACTIVITIESAdditions
                    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 ACTIVITIESAdvance
                    on borrowings
                
                
                3,872,457
                
                
                10,701,763
                
                
                78,861,250Payments
                    on debt
                
                
                (6,800,162
                )
                
                (7,608,056
                )
                
                (43,896,969
                )Proceeds
                    from sale of common stock
                
                
                8,346,518
                
                
                21,662,143
                
                
                14,528,107Proceeds
                    from sale of Series B preferred stock
                
                
                —
                
                
                —
                
                
                47,113,197Dividends
                    paid on Series B preferred stock
                
                
                —
                
                
                —
                
                
                (1,798,610
                )Net
                    cash provided by financing activities
                
                
                5,418,813
                
                
                24,755,850
                
                
                94,806,975NET
                    INCREASE IN CASH
                
                
                225,024
                
                
                1,529,951
                
                
                2,567,252CASH
                    AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
                
                
                637,522
                
                
                862,546
                
                
                2,392,497CASH
                    AND CASH EQUIVALENTS AT END OF PERIOD
                
                $
                862,546
                
                $
                2,392,497
                
                $
                4,959,749CASH
                    PAID FOR INTEREST
                
                $
                261,445
                
                $
                116,979
                
                $
                683,486CASH
                    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
                
                $
                8,974,868Other
                    comprehensive income tax:Change
                    in fair value of derivative instruments
                
                
                —
                
                
                —
                
                
                2,115,169Adjustment
                    for derivative gains reclassified into oil and gas sales
                
                
                —
                
                
                —
                
                
                (939,500
                )Other
                    comprehensive income, before income tax
                
                
                —
                
                
                —
                
                
                1,175,669Income
                    tax provision related to items of other comprehensive
                    income
                
                
                —
                
                
                —
                
                
                (399,727
                )Other
                    comprehensive income, net of income tax
                
                
                —
                
                
                —
                
                
                775,942Comprehensive
                    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
          of *GMX
          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.
          Net
          capitalized costs are limited to the estimated future net revenues, discounted
          at 10% per annum, from proved oil, natural gas, and natural gas liquid
          reserves.
          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.
  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.
  F-10
 **GMX
            Resources Inc. and Subsidiaries**
 **Notes
            to Consolidated Financial Statements**
 **December
            31, 2004, 2005 and 2006**
  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. 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.
  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
  F-11
 **GMX
            Resources Inc. and Subsidiaries**
 **Notes
            to Consolidated Financial Statements**
 **December
            31, 2004, 2005 and 2006**
 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.
  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
  F-12
 **GMX
            Resources Inc. and Subsidiaries**
 **Notes
            to Consolidated Financial Statements**
 **December
            31, 2004, 2005 and 2006**
  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
                
                25,000Range
                    of exercise prices
                
                $20.01-$29.00
                
                $39.65Weighted
                    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.
  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**
                  **December
                    31, 2004**
                ****
                **Year
                    Ended**
                  **December
                    31, 2005**Net
                    income as reported
                
                $
                1,441,773
                
                $
                7,156,096Add:
                    Stock-based compensation recognized
                
                
                —
                
                
                163,379Deduct:
                    Stock-based compensation, net of tax
                
                
                (316,085
                )
                
                (467,085
                )Pro
                    forma net earnings
                
                $
                1,125,688
                
                $
                6,852,390Pro
                    forma earnings per share - basic:
                
                $
                0.15
                
                $
                0.78Pro
                    forma earnings per share - diluted
                
                $
                0.15
                
                $
                0.75
 
 F-13
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
 The
          following table provides information related to stock option activity during
          2004, 2005 and 2006:
  **Number**
                  **o****f
                    shares**
                
                **Weighted
                    average**
                  **exercise
                    price**Balance
                    as of December 31, 2003
                
                
                139,000
                
                $
                5.69Granted
                
                
                190,000
                
                
                3.83Exercised
                
                
                (15,000
                )
                
                1.00Forfeited
                
                
                —
                
                
                —Expired
                
                
                —
                
                
                —Balance
                    as of December 31, 2004
                
                
                314,000
                
                $
                3.67Granted
                
                
                137,000
                
                
                16.58Exercised
                
                
                (128,250
                )
                
                2.69Forfeited
                
                
                —
                
                
                —Expired
                
                
                —
                
                
                —Balance
                    as of December 31, 2005
                
                
                322,750
                
                $
                8.65Granted
                
                
                53,000
                
                
                35.31Exercised
                
                
                (102,500
                )
                
                5.42Forfeited
                
                
                (3,000
                )
                
                27.91Expired
                
                
                —
                
                
                —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.
  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
  F-14
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 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
          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.
  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.
  F-15
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **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
                
                $
                1,764,631Liabilities
                    incurred
                
                
                295,756Liabilities
                    settled
                
                
                (474,601
                )Accretion(1)
                
                
                70,585Increase
                    due to revisions(2)
                
                
                555,862Balance
                    as of December 31, 2005
                
                $
                2,212,233Liabilities
                    incurred
                
                
                337,160Liabilities
                    settled
                
                
                —Accretion(8)
                
                
                81,646Decrease
                    due to revisions(9)
                
                
                (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.
  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.
  F-16
 **GMX
                Resources Inc. and Subsidiaries**
 **Notes
                to Consolidated Financial Statements**
 **December
                31, 2004, 2005 and 2006**
 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
                
                $
                173,050,284Not
                    subject to amortization:Acquired
                    in 2006
                
                
                —
                
                
                597,630Acquired
                    in 2005
                
                
                1,255,680
                
                
                288,262Acquired
                    in 2004
                
                
                432,880
                
                
                238,981Acquired
                    prior to 2004
                
                
                101,256
                
                
                —Accumulated
                    depreciation, depletion, andamortization
                
                
                (9,992,867
                )
                
                (16,874,796
                )Net
                    oil and gas properties
                
                
                58,927,397
                
                
                157,300,361Other
                    property and equipment
                
                
                17,044,734
                
                
                43,097,326Less
                    accumulated depreciation
                
                
                (1,793,781
                )
                
                (3,742,057
                )Net
                    other property and equipment
                
                
                15,250,953
                
                
                39,355,269Property
                    and equipment, net of accumulateddepreciation,
                    depletion, and amortization
                
                $
                74,178,350
                
                $
                196,655,630
 
 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 andgas
                    properties
                
                $
                1,707,431
                
                $
                3,496,657
                
                $
                6,881,930Depreciation
                    of other property and equipment
                
                
                336,054
                
                
                485,422
                
                
                1,164,243Total
                
                $
                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
                
                $
                40,000,000Joint
                    venture partner project (financing, non-recourse, no interest
                    rate)
                
                
                1,755,002
                
                
                1,820,2831,756,002
                
                
                41,820,283Current
                    portion
                
                
                345,967
                
                
                251,447Long
                    Term
                
                $
                1,410,035
                
                $
                41,568,836
  Maturities
            of long-term debt are as follows:
 
 **Year**
                
                **Amount**2007
                
                $
                251,4472008
                
                
                40,215,0442009
                
                
                171,9412010
                
                
                134,8032011
                
                
                184,0812012-2016
                
                
                584,6292017-2021
                
                
                188,005Thereafter
                
                
                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
  F-19
 **GMX
            Resources Inc. and Subsidiaries**
 **Notes
            to Consolidated Financial Statements**
 **December
            31, 2004, 2005 and 2006**
  financial
          ratios. As of December 31, 2006, the Company was in compliance with or
          obtained
          waivers for all the financial covenants of Loan Agreement.
  *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
                
                $
                27,115,255Statutory
                    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
                
                $
                9,454,770Statutory
                    depletion carry forwards
                
                
                2,274,900
                
                
                2,721,713Stock
                    option compensation expense
                
                
                —
                
                
                120,428Total
                
                
                11,546,900
                
                
                12,296,911Deferred
                    tax liabilities:Property,
                    plant and equipment
                
                
                (12,759,000
                )
                
                (16,924,111
                )Unrealized
                    gain on derivativeinstrument
                
                
                —
                
                
                (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,
  F-21
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
  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.
  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
                
                $
                190,6112008
                
                
                170,4022009
                
                
                169,1242010
                
                
                34,813Total
                
                $
                564,950
 
 Total
          rental expense for all operating leases is as follows for the years ended
          December 31:
  2004
                
                $
                153,6132005
                
                $
                118,7012006
                
                $
                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
  F-22
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
  which
          the
          Company shares are admitted to listed trading. The Option Plan will terminate
          in
          2010, except with respect to awards then outstanding.
  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
  F-24
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
  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.
  **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
                
                $
                1,124,873Producing
                    properties
                
                
                67,130,448
                
                
                173,050,28468,920,264
                
                
                174,175,157Less
                    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
                
                $
                597,630Development
                    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
                
                $
                31,882,072Production
                    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 gasproducing
                    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**
                  **(MBBLS)**
                
                **GAS**
                  **(MMCF)****December
                    31, 2004**Proved
                    reserves, beginning of period
                
                
                1,323
                
                
                45,029Extensions,
                    discoveries, and other additions
                
                
                51
                
                
                14,644Production
                
                
                (30
                )
                
                (1,049
                )Revisions
                    of previous estimates
                
                
                (107
                )
                
                (1,736
                )Proved
                    reserves, end of period
                
                
                1,237
                
                
                56,888Proved
                    developed reserves:Beginning
                    of period
                
                
                568
                
                
                18,277End
                    of period
                
                
                584
                
                
                18,980**December
                    31, 2005**Proved
                    reserves, beginning of period
                
                
                1,237
                
                
                56,888Extensions,
                    discoveries, and other additions
                
                
                694
                
                
                84,026Production
                
                
                (48
                )
                
                (1,930
                )Revisions
                    of previous estimates
                
                
                88
                
                
                11,192Proved
                    reserves, end of period
                
                
                1,971
                
                
                150,176Proved
                    developed reserves:Beginning
                    of period
                
                
                584
                
                
                18,980End
                    of period
                
                
                770
                
                
                41,503**December
                    31, 2006**Proved
                    reserves, beginning of period
                
                
                1,971
                
                
                150,176Extensions,
                    discoveries, and other additions
                
                
                831
                
                
                87,754Production
                
                
                (69
                )
                
                (3,915
                )Revisions
                    of previous estimates
                
                
                10
                
                
                7,926Proved
                    reserves, end of period
                
                
                2,743
                
                
                241,941Proved
                    developed reserves:Beginning
                    of period
                
                
                770
                
                
                41,503End
                    of period
                
                
                947
                
                
                70,801
 
 F-26
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
  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,**
                  **2004**
                
                **December
                    31,**
                  **2005**
                
                **December
                    31,**
                  **2006****(In
                    thousands)**
                
                **(In
                    thousands)**
                
                **(In
                    thousands)**Future
                    cash inflows
                
                $
                375,427
                
                $
                1,648,402
                
                $
                1,577,259Future
                    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
                
                
                529,000Less
                    effect of a 10% discount factor
                
                
                (101,121
                )
                
                (497,908
                )
                
                (332,985
                )Standardized
                    measure of discountedfuture
                    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
  F-27
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
  the
          tax
          basis of the properties involved giving effect to permanent differences,
          tax
          credits, and allowances relating to proved oil and gas reserves.
  Principal
          changes in the standardized measure of discounted future net cash flows
          attributable to the Company’s proved reserves are as follows:
  **December
                    31,**
                  **2004**
                  **(In
                    thousands)**
                
                **December
                    31,**
                  **2005**
                  **(In
                    thousands)**
                
                **December
                    31,**
                  **2006**
                  **(In
                    thousands)**Standardized
                    measure, beginning of year
                
                $
                47,975
                
                $
                64,231
                
                $
                302,396Sales
                    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 futuredevelopment
                    costs
                
                
                18,949
                
                
                223,384
                
                
                93,427Development
                    costs that reduced futuredevelopment
                    costs
                
                
                6,863
                
                
                23,629
                
                
                104,707Revisions
                    of quantity estimates
                
                
                (4,035
                )
                
                26,174
                
                
                17,399Sales
                    of reserves in place
                
                
                —
                
                
                —
                
                
                —Accretion
                    of discount
                
                
                1,149
                
                
                97,164
                
                
                40,962Changes
                    in timing of production and other
                
                
                (9,379
                )
                
                (78,118
                )
                
                (116,976
                )Net
                    changes in income taxes
                
                
                4,210
                
                
                (88,223
                )
                
                39,102Standardized
                    measure, end of year
                
                $
                64,231
                
                $
                302,396
                
                $
                196,015
 
 
 **NOTE
          M—QUARTERLY FINANCIAL DATA (UNAUDITED)**
  Summarized
          unaudited quarterly financial data for 2005 and 2006 are as
          follows:
  **First**
                  **Quarter**
                
                **Second**
                  **Quarter**
                
                **Third**
                  **Quarter**
                
                **Fourth**
                  **Quarter**
                
                **Total****2006**Revenues
                
                $
                6,715,890
                
                $
                6,493,516
                
                $
                8,534,070
                
                $
                10,289,212
                
                $
                32,032,688Income
                    before income taxes
                
                
                2,779,804
                
                
                1,942,117
                
                
                3,904,805
                
                
                3,763,242
                
                
                12,389,968Net
                    income
                
                
                2,134,327
                
                
                1,592,494
                
                
                2,860,905
                
                
                2,387,142
                
                
                8,974,868Net
                    income applicable tocommon
                    stock
                
                
                2,134,327
                
                
                1,592,494
                
                
                2,218,545
                
                
                1,230,892
                
                
                7,176,258Basic
                    earnings per share1
                
                
                0.20
                
                
                0.14
                
                
                0.20
                
                
                0.11
                
                
                0.65Diluted
                    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
                
                $
                19,192,704Income
                    before income taxes
                
                
                604,524
                
                
                914,864
                
                
                2,050,332
                
                
                4,798,476
                
                
                8,368,196Net
                    income
                
                
                604,524
                
                
                914,864
                
                
                2,050,332
                
                
                3,586,376
                
                
                7,156,096Net
                    income applicable tocommon
                    stock
                
                
                604,524
                
                
                914,864
                
                
                2,050,332
                
                
                3,586,376
                
                
                7,156,096Basic
                    earnings per share1
                
                
                0.07
                
                
                0.11
                
                
                0.20
                
                
                0.35
                
                
                0.81Diluted
                    earnings per share1
                
                
                0.07
                
                
                0.11
                
                
                0.20
                
                
                0.33
                
                
                0.79
 
 1The 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
 
 F-28
 **GMX
              Resources Inc. and Subsidiaries**
 **Notes
              to Consolidated Financial Statements**
 **December
              31, 2004, 2005 and 2006**
   **NOTE
          N—SUBSEQUENT EVENT** **- COMMON STOCK OFFERING**
  On
          February 7, 2006, 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 on Form 10-KSB for the year ended December 31,
              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-A filed on August 5,
              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)







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)







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 Accountants31.1
            Rule
                13a-14(a) Certification of Chief Executive Officer31.2
            Rule
                13a-14(a) Certification of Chief Financial Officer32.1
            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.