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                    U. S. SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   FORM 10-KSB

[X]    ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934
       For the fiscal year ended December 31, 2005

[_]    TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
       ACT OF 1934
       For the transition period from __________________ to __________________

                        Commission file number 000-32325

                               GMX RESOURCES INC.
                 (Name of small business issuer in its charter)

              OKLAHOMA                                    73-1534474
   (State or other jurisdiction                        (I.R.S. Employer
         of incorporation)                            Identification No.)

          9400 North Broadway, Suite 600, Oklahoma City, Oklahoma 73114
                    (Address of principal executive offices)

(Issuer's Telephone Number)          (405) 600-0711

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

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

                         COMMON STOCK, $0.001 PAR VALUE
                                (Title of Class)

Check whether the issuer is not required to file reports pursuant to Section 13
or 15(d) of the Exchange Act [_].

Check whether the issuer (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. [X] Yes [_] No

Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. [_]

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 126 of the Exchange Act). [_] Yes [X] No

The issuer's revenue for the year ended December 31, 2005 was $19,192,704.

The aggregate market value of the voting and non-voting common equity held by
non-affiliates on March 23, 2006 was $390.8 million. This amount was computed
using closing price of the issuer's common stock on March 23, 2006 on the NASDAQ
National Market.

As of March 28, 2006, the issuer had outstanding a total of 11,192,467 shares of
its $0.001 par value Common Stock.

Documents incorporated by reference - NONE

Transitional Small Business Disclosure Format (Check one):  Yes [_]  No [X]

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                               GMX RESOURCES INC.
                                   FORM 10-KSB
                                TABLE OF CONTENTS

                                                                            Page
                                                                            ----

PART I.........................................................................1

Item 1.      BUSINESS..........................................................1

             General...........................................................1
             General Development of Our Business...............................1
             Business Strategy.................................................4
             2006 Plans........................................................5
             Marketing.........................................................5
             Regulation........................................................6
             Gas Gathering.....................................................9
             Competition.......................................................9
             Facilities........................................................9
             Employees........................................................10
             Certain Technical Terms..........................................10

Item 2.      PROPERTIES.......................................................14

             General..........................................................14
             East Texas.......................................................14
             Northwestern Louisiana...........................................16
             Southeast New Mexico.............................................17
             Reserves.........................................................17
             Costs Incurred...................................................19
             Productive Well Summary..........................................20

Item 3.      LEGAL PROCEEDINGS................................................21


Item 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..............21


PART II.......................................................................22

Item 5.      MARKET FOR COMMON EQUITY RELATED STOCKHOLDER MATTERS AND SMALL
             BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES...................22

             Common Stock.....................................................22
             Equity Compensation Plan Information.............................22
             Recent Sales of Unregistered Securities..........................23
             Purchases of Equity Securities...................................23

Item 6.      MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION........24

             Selected Financial Data..........................................24
             Summary Operating and Reserve Data...............................25
             Critical Accounting Policies.....................................26

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             Results of Operations for the Year Ended December 31, 2005
             Compared to the Year Ended December 31, 2004.....................28
             Results of Operations for the Year Ended December 31, 2004
             Compared to the Year Ended December 31, 2003.....................29
             Capital Resources and Liquidity..................................30
             Credit Facility..................................................31
             Other 2005 Financings and 2006 Warrant Exercises.................32
             Working Capital..................................................32
             Commitments and Capital Expenditures.............................33
             Liquidity and Financing Considerations...........................33
             Price Risk Management............................................34
             Effect of Accounting Standards...................................34
             Forward-Looking Statements.......................................35
             Risks Related to GMX.............................................35
             Risks Related to the Oil and Gas Industry........................39

Item 7.      FINANCIAL STATEMENTS.............................................43


ITEM 8.      CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
             AND FINANCIAL DISCLOSURE.........................................43


Item 8A.     CONTROLS AND PROCEDURES..........................................44


Item 8B.     OTHER INFORMATION................................................44


PART III......................................................................45

Item 9.      DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
             COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT................45

             Directors and Executive Officers.................................45
             Significant Employees............................................46
             Terms............................................................46
             Section 16(a) Beneficial Ownership Reporting Compliance..........46
             Audit Committee Matters..........................................47
             Code of Ethics...................................................47

Item 10.     EXECUTIVE COMPENSATION...........................................48

             Summary Compensation Table.......................................48
             Compensation of Directors........................................49

Item 11.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
             AND RELATED STOCKHOLDER MATTERS..................................49


Item 12.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...................50


Item 13.     EXHIBITS.........................................................50


Item 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES...........................50


SIGNATURES....................................................................51

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS...................................F-1

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                                     PART I

ITEM 1.       BUSINESS

GENERAL

            GMX Resources Inc. (referred to herein as "we," "us," "GMX" or the
"Company") is an independent natural gas producer headquartered in Oklahoma
City, Oklahoma. As of December 31, 2005, our principal drilling and development
activities were focused on our property base in the East Texas, North Carthage
Field in Harrison and Panola counties, which we are drilling in 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,
2005, we had proved reserves of 162 Bcfe and 97 gross (60.1 net) producing
wells. In the North Carthage Field, we also held a large inventory of Cotton
Valley Sand development prospects, including 26,395 gross (3,814 net) acres and
619 gross and 374 net CVS possible drilling locations depending on the area of
well spacing. Our strategy is to develop our East Texas resource play with
multiple rigs, increase production, grow our natural gas reserves and continue
to build shareholder value.

            During 2005 we accelerated our drilling in East Texas and expect to
further accelerate drilling in 2006. We expect to continue to evaluate all
strategic alternatives available to enhance growth and shareholder value. We
believe further aggressive development of our East Texas resource play will
enhance cash flow and further prove the value of undeveloped reserves. We
carefully evaluate all opportunities that may be presented from time to time but
do not have a fixed plan for any sale or merger of the Company. Our management
team has a significant equity position in the Company and, accordingly,
management's interests are aligned with the 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.

GENERAL DEVELOPMENT OF OUR BUSINESS

ORGANIZATION

            At the time of our organization in 1998, we acquired from an
unrelated third party for $6.0 million, producing and undeveloped properties
located primarily in East Texas and northwestern Louisiana, Kansas and
southeastern New Mexico. When we acquired them, the properties consisted of 71.1
net producing wells, 20,829 net developed and 317 net undeveloped acres. At the
acquisition date, the properties had estimated proved developed producing
reserves of 5 Bcfe. These properties were acquired out of a bankruptcy
reorganization of a small, privately held company. We believed the properties
had not been developed to their full potential as a result of the financial
condition and lack of technical geological expertise of the prior owner.
However, there was substantial high quality geological and engineering data
available for the properties, waiting to be evaluated.

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2001 EQUITY OFFERINGS AND DRILLING

            In February 2001, we completed an initial public offering of
1,250,000 units at $8.00 per unit. Each unit consisted of one share of common
stock, one Class A warrant to purchase one share of common stock and one Class B
warrant to purchase one share of common stock. The Class B warrants expired
unexercised. The Class A Warrants are exercisable for $12 per share of common
stock and expired on February 12, 2006. The net proceeds of the offering of
approximately $8.5 million were used primarily for development drilling in 2001.

            In July 2001, we completed a secondary public offering of 2,300,000
shares of common stock at an offering price of $5.50 per share. The proceeds of
the offering, net of underwriters' fees and other expenses, were approximately
$11.3 million, and were used primarily for the development drilling of oil and
gas wells in 2001 and early 2002.

            In 2001, we drilled and completed 10 gross (10 net) new gas wells in
our East Texas properties.

DRILLING CONTRACT

            In May 2001, we entered into a drilling contract with Nabors
Drilling USA, LP ("Nabors"), obligating us to use two 10,000-foot drilling rigs
and crews on a continuous basis for a period of two years at a cost of $14,000
per day per rig. Our payment obligations were secured by standby letters of
credit in the aggregate amount of $1,000,000, $500,000 per rig.

            In December 2001, we terminated the contract and filed a lawsuit in
the United States District Court for the Western District of Oklahoma against
Nabors alleging that Nabors made misrepresentations intended to induce us to
enter into the drilling contracts as well as alleging that Nabors breached those
contracts by providing substandard drilling services. Nabors drew the full
$1,000,000 on the letters of credit and counterclaimed for approximately
$10,000,000 alleged to be owed for an early termination fee and unpaid invoices.
In December 2002, we received a jury verdict in our favor. In May 2003, we
settled the lawsuit with no monetary consequences to either party.

2002 AND 2003 ACTIVITIES

            Due to liquidity issues from the uncertainties associated with the
Nabors litigation, as well as technical defaults under our credit facility, we
curtailed all drilling and development activities in 2002 and 2003 and
implemented a number of actions to reduce overhead costs. In addition, in 2002,
we completed the sale of all of our oil and gas properties in Kansas which had
proved reserves of 9,571 Mmcfe and applied substantially all of the $3.6 million
in net proceeds to our bank debt. We also pursued a possible sale of our East
Texas properties but suspended this process after our success in the trial court
in the Nabors litigation.

            In December 2003, we executed a definitive participation agreement
with PVOG for the joint development of our Cotton Valley, Travis Peak and Pettit
prospects located in East Texas. We also entered into several amendments to the
agreement in 2004. 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
(or "JV 30% Area"), which includes approximately 7,817 gross (2,173 net) acres

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comprising a portion of our proved undeveloped acreage. We have a 20% carried
interest in the first seven wells drilled in the JV 30% Area (which have all
been completed) and a right to participate for up to 30% of additional JV 30%
Area wells. Phase II (or "JV 50% Area"), which includes approximately 6,931
gross (3,325 net) acres of our acreage, commenced in 2005. In the JV 50% Area,
we have a 20% carried interest in the first two wells (which have been
completed) and will have a right to participate for up to 50% of additional
drilling in the JV 50% Area. In December 2003, we received approximately
$950,000 in acreage and drilling location cost reimbursement that was applied to
reduce current liabilities. The participation agreement designates another Phase
III (or "GMXR 100% Area") in which we have exclusive drilling and development
rights and PVOG has a preferential right to purchase. For additional information
concerning the PVOG agreement, see "Item 2 - Properties."

2004 ACTIVITIES

            In January 2004, we completed a private placement of $1 million of
11% senior subordinated notes maturing in 2007 and five year warrants to
purchase 175,000 shares of common stock for $1.50 per share. The proceeds of
this placement were used for completion of wells with proved developed
non-producing reserves, other production enhancements, reduction in current
liabilities, placement fees and transaction costs associated with the
transaction. These notes were repaid with bank debt in June 2004. In addition,
during 2004, the warrants were all exercised for total proceeds of $262,500.

            In addition, in April 2004, we closed a private placement of 200,000
shares of common stock for $1,000,000 with a single institutional investor. In
June 2004, we closed another private placement of 1,100,000 shares of common
stock for $7,535,000 with a group of institutional investors. Proceeds of both
these placements were used primarily to fund drilling and development activity
in our East Texas properties.

            During 2004, PVOG drilled 17 Cotton Valley wells and completed 15
wells in Phase I under our participation agreement. For 7 of these wells, we had
a 20% carried interest and participation for cost for an additional 10% in two
of the carried wells. For the remaining wells, we participated with a 30%
interest. At December 31, 2004, PVOG was in the process of completing the
remaining two wells. During 2004, we conducted recompletion or production
enhancement operations on eight wells in Phase III in which we have 100% working
interest. These wells have been recompleted in the Pettit, Travis Peak and
Cotton Valley formations.

2005 ACTIVITIES

            In April 2005, we signed a commitment letter for a line of credit
with Hibernia National Bank headquartered in New Orleans, Louisiana for a
reserve-based, revolving credit facility, which was formalized in July of 2005.
The initial borrowing base was $17 million at the LIBO rate, plus 1.5% to 2.25%,
depending on usage. On December 1, 2005, the borrowing base was increased to $24
million. At December 31, 2005, only $1,000 had been advanced under this
facility.

            In addition, in July 2005, we closed a private placement of
1,600,000 shares of common stock for $21.6 million with a group of institutional
investors. Proceeds of this placement were used primarily to fund drilling and
development activity in our East Texas properties.

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            During 2005, PVOG drilled and completed 21 gross wells, 5.7 wells
net to GMX, in the JV 30% and JV 50% areas.

            In the GMXR 100% Area, we drilled 8 wells and completed 5 before
year-end. The other 3 were completed in early 2006.

            In December 2005, we acquired from McLachlan Drilling Co. for our
own use a drilling rig that was previously drilling for us under a term drilling
contract. The purchase price was $5.1 million. We have also contracted to
acquire an additional rig, which is being constructed. This rig is expected to
be available for us in the 2nd quarter of 2006. As noted above, these rigs will
be used for drilling in the GMXR 100% Area.

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 and recompletion projects with an
estimated 114 Bcfe of proved undeveloped reserves as of December 31, 2005. These
projects include 184 new drilling locations 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, 2005 reserve report, the pre-tax present value of the proved
reserves is $411 million with anticipated future development costs of $191
million.

            SIGNIFICANT INVENTORY OF UNPROVED PROSPECTS. We have approximately
432 gross/279 net additional drilling locations in East Texas which we believe
have potential in the Pettit, Travis Peak and Cotton Valley formations at depths
of 6,000 to 10,000 feet. Approximately 20,928 acres of our leasehold position is
held by production, so we do not have rental payments and drilling targets on
those leases, they can be held and drilled in order of priority without concern
about lease expiration.

            EMPHASIS ON GAS RESERVES. Production for 2005 was 87% gas and 13%
oil. Proved reserves as of December 31, 2005 are 93% gas and 7% oil. We intend
to emphasize acquisition

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and 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 2005, we and PVOG acquired rights to use
additional rigs to accelerate development and we expect further acceleration in
2006. We consider that our relationship with PVOG is good.

            CONTROL OF RIGS. In December 2005 we organized a wholly owned
subsidiary, Diamond Blue Drilling Co. ("DBD"), which purchased a 12,500-foot
depth drilling rig we previously had under contract and DBD expects to acquire
an additional 14,000-foot depth rig which is under construction in the second
quarter of 2006. These rigs will be used to drill in the GMXR 100% Area and
enable us to guarantee rig availability and drill at reduced costs.

2006 Plans

             By the end of 2006, we and PVOG expect to have up to 6 drilling
rigs in operation in East Texas, including the 2 rigs owned by us. Current plans
include drilling of up to 28 gross/8.4 net wells in the JV 30% Area, up to 17
gross/8.5 net wells in the JV 50% Area and up to 30 wells in the GMXR 100% Area.
Our share of the capital expenditures for these wells is estimated to range from
$72 to $93 million. Completion of these plans will depend on drilling results,
rig availability and other factors. We will also participate in wells in New
Mexico. See "Properties."

MARKETING

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

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

            Substantially all of our gas from our East Texas company-operated
wells is initially sold to our wholly owned subsidiary, Endeavor Pipeline Inc.
("Endeavor"), which in turn sells gas to unrelated third parties. All of our gas
is currently sold under contracts providing for market sensitive terms which are
terminable with 30-60 day notice by either party without penalty. This

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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 GMXR
markets 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.

            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 intend to enter into any long-term contracts to
sell natural gas or crude oil or to enter into any hedging transactions. None of
our gas or oil sales contracts have a term of more than one year.

            In 2005, our largest purchasers were Crosstex Pipeline Company, PVOG
and TEPPCO Crude, which accounted for 33%, 38% and 14% of total oil and natural
gas sales. We do not believe that the loss of any of our purchasers would have a
material adverse affect on our operations as there are other purchasers active
in the market.

REGULATION

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

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

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

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Discharged hydrocarbons may migrate through soil to water supplies or adjoining
property, giving rise to additional liabilities.

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

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

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

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

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abandonment of oil and gas wells which have been unproductive. Numerous state
laws and regulations also relate to air and water quality.

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

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

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

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

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

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

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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, 2005, this gathering system
consisted of approximately 64 miles of gathering lines and four Ajax DPC-360,
360 horsepower, two-stage compressor that collect and compress gas from
approximately 97% of our gas production from company-operated wells in 2005.
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 "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.

COMPETITION

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

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

FACILITIES

            As of December 31, 2005, we leased approximately 6,749 square feet
in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental
cost is approximately $89,235.

                                       9
<PAGE>

EMPLOYEES

            As of December 31, 2005, we had 16 full-time employees of which four
are management and the balance are clerical or technical employees. This
compares to eleven full-time employees at December 31, 2004, reflecting the
increase in our activities in 2005. We also use nine independent contractors to
assist in field operations. We expect to add additional personnel in 2006 as our
activities continue to increase. We believe our relations with our employees are
satisfactory. Our employees are not covered by a collective bargaining
agreement.

CERTAIN TECHNICAL TERMS

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

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

            BCF. Billion cubic feet.

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

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

            BBTU. Billion Btus.

            DEVELOPED ACREAGE. The number of acres which are allocated or
assignable to producing wells or wells capable of production.

            DEVELOPMENT LOCATION. A location on which a development well can be
drilled.

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

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

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

            ESTIMATED FUTURE NET REVENUES. Estimated future gross revenue to be
generated from the production of proved reserves, net of estimated production,
future development costs, and future abandonment costs, using prices and costs
in effect as of the date of the report or estimate, without giving effect to
non-property related expenses such as general and administrative

                                       10
<PAGE>

expenses, debt service and future income tax expense or to deprecation,
depletion and amortization.

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

            GROSS ACRE. An acre in which a working interest is owned.

            GROSS WELL. A well in which a working interest is owned.

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

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

            LEASE OPERATING EXPENSE. All direct costs associated with and
necessary to operate a producing property.

            MBBLS. Thousand barrels.

            MBTU. Thousand Btus.

            MCF. Thousand cubic feet.

            MCFPD. Thousand cubic feet per day.

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

            MMBBLS. Million barrels.

            MMBTU. Million Btus.

            MMCF. Million cubic feet.

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

            NATURAL GAS LIQUIDS. Liquid hydrocarbons which have been extracted
from natural gas (e.g., ethane, propane, butane and natural gasoline).

            NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.

            NYMEX. New York Merchantile Exchange.

                                       11
<PAGE>

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

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

            PRODUCTIVE WELL. A well that is producing oil or gas or that is
capable of production.

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

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

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

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

            ROYALTY. An interest in an oil and natural gas lease that gives the
owner of the interest the right to receive a portion of the production from the
leased acreage (or of the proceeds of the sale), but generally does not require
the owners to pay any portion of the costs of drilling or

                                       12
<PAGE>

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.




                                       13
<PAGE>

ITEM 2.       PROPERTIES

GENERAL

            As of December 31, 2005, we owned properties in the following
productive fields and basins in the United States:

                        o East Texas, North Carthage Field and NE Louisiana,
                          Waskom Field;

                        o The Tatum Basin Crossroads in Southeast New Mexico.

            The following table sets forth certain information regarding our
activities in each of these areas as of December 31, 2005.

<TABLE><CAPTION>
                                                                   EAST TEXAS
                                                                      AND             SOUTHEAST
                                                                   LOUISIANA          NEW MEXICO         TOTAL
                                                                   ---------          ----------         -----
<S>                                                                 <C>                 <C>             <C>
          PROPERTY STATISTICS:
          --------------------
          Proved reserves (MMcfe)                                   158,957             3,046           162,003
          Percent of total proved reserves                               98%                2%              100%
          Gross producing wells                                          90                 7                97
          Net producing wells                                          54.7               5.4              60.1
          Gross acreage                                              29,023             1,920            30,943
          Net acreage                                                15,706             1,458            17,164
          Proved developed reserves (MMcfe)                          45,023             1,100            46,123
          Proved undeveloped reserves (MMcfe)                       113,934             1,946           115,880
          Estimated total future development costs ($000s)          189,521             1,179           190,700
          Estimated 2006 development costs ($000s)                   90,000             2,000            92,000
          Proved undeveloped locations                                  184                 3               187

          YEAR ENDED DECEMBER 31, 2005 RESULTS:
          Production (net MMcfe)                                      2,108               112             2,220
          Average net daily production (Mcfe)                         5,775               307             6,082
</TABLE>

            Additional information related to our oil and gas activities is
included in Notes J and K 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 28,423 gross (15,337
net) acres with rights covering the Travis Peak, Pettit, Glen Rose and Cotton
Valley formations. Our East Texas properties have 158.6 Bcfe of proved reserves
or 98% of our total proved reserves at December 31, 2005, of which 113.9 Bcfe is
classified as proved undeveloped.

                                       14
<PAGE>

            We have interests in 85 gross (52.0 net) producing wells in East
Texas, of which we operate 43. Average daily production net to our interest for
2005 was 4,731 Mcf of gas and 98 Bbls of oil. Production is primarily from the
Betheny, 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. The
Blocker and Betheny areas include 39 gross (36.6 net) wells in Harrison County
which produce gas that is gathered, compressed and sold by Endeavor. Gas sold
from the Blocker area has a high MMBtu content which results 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 contracts.

            The undeveloped acreage in these areas lies on Sabine Uplift just
north of the Carthage Field. The area has 29 producing reservoirs at depths from
3,000 to 10,000 feet. The reservoir trends are similar to river channels and
beach barrier bars and are generally substantial in length and sometimes width.
These features occur in more than one producing horizon and we give first
priority to drilling locations where a single well can drill through two or more
producing zones. This increases the reserves recoverable through a single
wellbore. We believe the natural gas development opportunities on this property
base are substantial and abundant. Our proved developed non-producing and proved
undeveloped reserves are significant in this region consisting of 48.8 Bcfe,
frequently located at the intersection of multiple crossing reservoir trends.
Each well generally penetrates multiple potentially productive formations,
including the Pettit, Travis Peak and Cotton Valley.

            On December 29, 2003, we executed a definitive 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. 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 approximately 9,908 gross (2,833 net) acres
comprising a portion of our proved undeveloped acreage. GMX has a 20% carried
interest in the first wells drilled in the JV 30% Area and a right to
participate for 30% of additional wells. PVOG has drilled and completed 36 wells
in the JV 30% Area. Phase II (the "JV 50% Area") includes approximately 8,052
gross (3,864 net) acres. We have a 20% carried interest in the first two wells
and a right to participate for up to 50% of additional drilling in the JV 50%
Area. During 2005 PVOG drilled and completed 3 wells in this area. At inception,
we received 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 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 acres and a 50% PVOG/50% GMX sharing ratio. The
Phase III (the "GMXR 100% Area") AMI consists of 15,360 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

                                       15
<PAGE>

acreage in the GMXR 100% Area. In 2004, we jointly acquired 2,665 gross acres in
the JV 30% Area and 670 acres in the JV 50% Area. In 2005 we jointly acquired
2,091 gross acres (660 net) in the JV 30% Area and 1,121 gross acres (539 net)
in the JV 50% Area. During 2005 we acquired 2,481 gross acres (1,850 net) in the
GMXR 100% Area. Also, during 2005 we drilled and completed 8 wells in the GMXR
100% Area.

            The participation agreement originally limited PVOG to the use of
one rig. During a portion of 2004, PVOG used two rigs under an amendment to our
agreement whereby PVOG agreed to purchase a dollar denominated production
payment from us to finance our share of costs of drilling using the second rig.
This arrangement was terminated in November 2004 and since that date, only one
rig was used throughout the remainder of 2004 and early 2005. We received
$1,929,029 in funding from PVOG under this arrangement, which is repayable from
75% of our share of production proceeds from the wells financed. In March 2005,
we entered into a further amendment to the joint participation agreement
permitting PVOG to use two rigs, when one can be located, which permits us to
share in the use of the second rig for our own account in drilling in Phase III,
on an alternating basis with PVOG. We and PVOG each have the right to use the
second rig for up to three consecutive wells. We will pay for the rig when we
use it on the same terms as PVOG. Effective January 1, 2006, we agreed that PVOG
could use two additional rigs. Either party may terminate the multiple rig
provisions on 60 days notice subject to the terms of any drilling contract for
the second rig.

            Our success rate has been 100% on wells drilled and completed in
2004 and 2005. There is a potential for up to 619 gross (374 net) locations of
Cotton Valley wells in our East Texas acreage assuming an ultimate well density
of two wells in each 80-acre tract.

            At December 31, 2005, Sproule Associates, Inc., our independent
reserve engineering firm, assigned a total of 25,925 Bcfe of proved producing
reserves to the completed East Texas wells, 18,740 Bcfe to our proved developed
non-producing wells, and 113,934 Bcfe of proved undeveloped reserves to our 184
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 2006,
we expect PVOG to drill 20-28 new Cotton Valley wells in the JV 30% Area and
10-17 Cotton Valley wells in the JV 50% Area and we expect to drill up to 30
Cotton Valley wells in the GMXR 100% Area. We also plan to recomplete 4-6 wells
in the GMXR 100% Area. We will fund our share of this drilling at the low end of
these ranges from internal cash flow and borrowings under our bank credit
facility. If drilling is proposed at the higher ranges, we may need outside
sources of capital to fund our share, which we expect to fund through additional
borrowings rather than sales of additional equity. In 2005 and through February
2006 when our Class A warrants expired, we received $14 million from the
exercise of warrants.

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 five gross

                                       16
<PAGE>

(2.6 net) producing wells, three of which we operate. Production is
predominately oil. Louisiana proved reserves are 0.4 Bcfe and represent
approximately 1% of proved reserves as of December 31, 2005. Average daily
production net to our interest for 2005 was 2 Bbls of oil and 22 Mcf of gas.

SOUTHEAST NEW MEXICO

            Our Southeast New Mexico properties are located in Lea and Roosevelt
counties and consist of approximately 1,920 gross (1,458 net) acres. The acreage
lies on the northwestern edge of the Midland Basin, defined as the Tatum Basin.
Existing production is from three zones--the Bough C, Abo and San Andres--at
depths ranging from 9,500 to 10,000 feet. Proved reserves in Southeast New
Mexico are 3.0 Bcfe and represent 2% of our total proved reserves as of December
31, 2005. Average daily production net to our interests for 2005 from our 7
gross (5.4 net) producing wells in this area was 124 Mcf of gas and 25 Bbls of
oil.

            Third party drilling activity in the vicinity of our properties also
suggests that deeper exploration may be warranted to the Atoka, Morrow, and
Devonian formations. In 2004, we entered into a farmout with Yates Petroleum
Corporation which completed 3D seismic evaluations of these formations. GMX
farmed out its 320-acre leasehold interest to Yates Petroleum Corporation
retaining a 25% working interest before payout with an overriding royalty
convertible to 30% working interest after payout. This 320-acre leasehold is
part of a 960.17-acre AMI wherein three Morrow wells have been proposed under
our operating agreement with Yates.

            GMX's interests in these three wells named the Gosden BGI State #1,
Twitty BFH State #1 and Huskey "Big" State #1 are as follows:

            Before Payout Working Interest                     7.6694%
            Before Payout Net Revenue:                         6.710725%
            Convertible Overriding Royalty Interest:           2.229072%

            After Payout Working Interest                      14.5719%
            After Payout Net Revenue                           12.750413%


            The Gosden #1 was drilled and completed in the second quarter 2005
and reached payout status 31 days after first sales. GMX elected to covert its
Overriding Royalty Interest in the Gosden #1 increasing its net revenue from
8.935 to 12.75%. The Twitty #1 and Huskey #1 are scheduled for drilling in the
first quarter of 2006. GMX has a carried interests in these two wells identical
to the Gosden #1.

            We also plan to drill approximately 14 wells in the San Andres
formation at 5,500' approximate depth in 2006.

RESERVES

            As of December 31, 2005, Sproule Associates Inc. estimated our
proved reserves to be 162 Bcfe. An estimated 46 Bcfe is expected to be produced
from existing wells and another 116 Bcfe or 72% of the proved reserves, is
classified as proved undeveloped. All of our proved

                                       17
<PAGE>

undeveloped reserves are on locations that are adjacent to wells productive in
the same formations. As of December 31, 2005, we had interests in 97 gross
producing wells, 43 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.

<TABLE><CAPTION>
                                                                      YEARS ENDED DECEMBER 31,
                                                          ------------------------------------------------
                                                             2003              2004                2005
                                                          -----------       -----------         ----------
<S>                                                            <C>               <C>                <C>
PROVED DEVELOPED:
Gas (MMcf)                                                     18,277            18,980             41,503
Oil (MBbls)                                                       568               584                770
                                   Total (MMcfe)               21,685            22,484             46,123
PROVED UNDEVELOPED:
Gas (MMcf)                                                     26,752            37,908            108,673
Oil (MBbls)                                                       755               653              1,201
                                   Total (MMcfe)               31,282            41,826            115,880
TOTAL PROVED:
Gas (MMcf)                                                     45,029            56,888            150,176
Oil (MBbls)                                                     1,323             1,237              1,971
                                   Total (MMcfe)               52,967            64,309            162,003

ESTIMATED FUTURE NET REVENUES (1)($000S)                  $   178,348       $   214,278         $1,648,402

PRESENT VALUE(1)($000S)                                   $    71,192       $    83,237         $  409,624

STANDARDIZED MEASURE (1) ($000S)                          $    47,975       $    64,231         $  302,396
</TABLE>
-------------------------

(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 K - Supplemental Information on Oil and Gas
            Operations" for information about the standardized measure of
            discounted future net cash flows. We believe that the Estimated
            Future Net Revenue and Present Value are useful measures in addition
            to standardized measure as it assists in both the determination of
            future cash flows of the current reserves as well as in making
            relative value comparisons among peer companies. The standardized
            measure is dependent on the unique tax situation of each individual
            company, while the pre-tax Present Value is based on prices and
            discount factors which are consistent from company to company. We
            also understand that securities analysts use this measure in similar
            ways.

            The increase in proved reserves in 2005 is primarily attributable to
extensions and discoveries and revisions of prior estimates resulting from our
East Texas drilling results.

            Approximately 72% 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 $190 million as of December 31, 2005, of which $92 million

                                       18
<PAGE>

is scheduled to be expended in 2006. 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, 2005 were $61.04 per
barrel for oil and $11.225 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 $.10 per Mcf change in gas prices from those used in
calculating the Present Value would change such Present Value by $807,000, and
$5,723,000, respectively, as of December 31, 2005.

            Sproule Associates, Inc., our independent reserve engineers,
prepared the estimates of proved reserves as of December 31, 2003, 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
Securities and Exchange Commission.

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.

<TABLE><CAPTION>
                                                    YEAR ENDED DECEMBER 31,
                                        -------------------------------------------------
                                           2003               2004                2005
                                        -----------        -----------        -----------
<S>                                     <C>                <C>                <C>
PROPERTY ACQUISITION COSTS:
                        Proved          $    57,565        $      --          $      --
                        Unproved              5,212            851,617          1,230,409
DEVELOPMENT COSTS                           173,840          7,681,750         24,789,281
                                        -----------        -----------        -----------
                        Total           $   236,617        $ 8,533,367        $26,019,690
                                        ===========        ===========        ===========
</TABLE>

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.

                                       19
<PAGE>

<TABLE><CAPTION>
                                                  YEAR ENDED DECEMBER 31,
                         -----------------------------------------------------------------------
                                2003                       2004                      2005
                         ------------------         ------------------        ------------------
<S>                      <C>          <C>           <C>          <C>          <C>          <C>
DEVELOPMENT WELLS:       Gross         Net          Gross         Net         Gross         Net
Gas                        --           --             15            4           31           16
Oil                        --           --           --           --           --           --
Dry                        --           --           --           --           --           --
                         -----        -----         -----        -----        -----        -----
Total                      --           --             15            4           31           16
                         =====        =====         =====        =====        =====        =====
</TABLE>

ACREAGE

            The following table shows our developed and undeveloped oil and gas
lease and mineral acreage as of December 31, 2005. 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          19,915       11,820        9,108        3,887
Southeast New Mexico               1,920        1,458         --           --
                                --------     --------     --------     --------
                   Total          21,835       13,278        9,108        3,887
                                ========     ========     ========     ========

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

PRODUCTIVE WELL SUMMARY

            The following table shows our ownership in productive wells as of
December 31, 2005 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                                     77         44.7
          Oil                                     20         15.4
                                            --------     --------
                          Total                   97         60.1
                                            ========     ========

                                       20
<PAGE>

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 2005.
































                                       21
<PAGE>

                                     PART II

ITEM 5.       MARKET FOR COMMON EQUITY RELATED STOCKHOLDER MATTERS AND SMALL
              BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK

            The high and low bid prices for our Common Stock as listed on the
NASDAQ National Market as applicable during the periods described below were as
follows:

                                                      HIGH          LOW
                                                      ----          ---
          YEAR ENDED DECEMBER 31, 2004
                   First Quarter                    $   6.08     $   2.45
                   Second Quarter                       8.30         5.10
                   Third Quarter                        7.80         5.31
                   Fourth Quarter                       7.75         5.86
          YEAR ENDED DECEMBER 31, 2005
                   First Quarter                       13.29         6.22
                   Second Quarter                      14.69         9.53
                   Third Quarter                       27.00        13.69
                   Fourth Quarter                      42.27        20.66

These quotations reflect inter-dealer prices, without retail mark-up, mark-down
or commission and may not represent actual transactions.

            As of March 10, 2006, there were 33 record owners of our Common
Stock and approximately 6,897 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 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.

EQUITY COMPENSATION PLAN INFORMATION

            The following table sets forth information as of December 31, 2005
relating to equity compensation plans.



                                       22
<PAGE>

<TABLE><CAPTION>
                                         NUMBER OF
                                        SHARES TO BE   WEIGHTED-AVERAGE
                                        ISSUED UPON        EXERCISE         REMAINING SHARES
                                        EXERCISE OF        PRICE OF       AVAILABLE FOR FUTURE
                                        OUTSTANDING       OUTSTANDING     ISSUANCE UNDER EQUITY
        PLAN CATEGORY                     OPTIONS           OPTIONS        COMPENSATION PLANS
        -------------                     -------           -------        ------------------
<S>                                      <C>                 <C>                 <C>
Equity Compensation Plans
Approved by Shareholders                 295,750             $9.35               158,991

Equity Compensation Plans Not
Approved by Shareholders                  27,000             $1.00                  ---
</TABLE>

            The 27,000 shares issuable under the equity compensation plan not
approved by shareholders relate to a single option grant to a consultant as a
part of his compensation arrangements.

RECENT SALES OF UNREGISTERED SECURITIES

            None during the fourth quarter of 2005.

PURCHASES OF EQUITY SECURITIES

            None during the fourth quarter of 2005















                                       23
<PAGE>

ITEM 6.       MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

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 the discussion below.

<TABLE><CAPTION>
                                                                      YEARS ENDED DECEMBER 31,
                                                           ------------------------------------------------
                                                               2003              2004              2005
                                                           ------------      ------------      ------------
<S>                                                        <C>               <C>               <C>
STATEMENT OF OPERATIONS DATA:
Oil and gas sales                                          $  5,367,370      $  7,689,882      $ 19,026,050
Interest and other income                                        21,424           143,828           166,654
                                                           ------------      ------------      ------------
            Total revenues                                    5,388,794         7,833,710        19,192,704
                                                           ------------      ------------      ------------
Lease operations                                                850,034         1,261,109         2,070,286
Production and severance taxes                                  384,069           518,712         1,241,338
General and administrative                                    1,578,865         1,985,913         3,388,396
Depreciation, depletion and amortization                      1,549,678         2,043,485         3,982,079
Interest                                                        439,313           558,504           142,409
                                                           ------------      ------------      ------------
            Total expenses                                 $  4,801,959      $  6,367,731      $ 10,824,508
                                                           ------------      ------------      ------------
Income (loss) before income taxes                               586,835         1,465,979         8,368,196
Income tax expense - current                                       --              24,206              --
Income tax expense - deferred                                      --                --           1,212,100
                                                           ------------      ------------      ------------
Net income before cumulative effect of a change in
   accounting principle                                    $    586,835      $  1,441,773      $  7,156,096

Cumulative effect of a change in accounting principle           (51,834)             --                --
                                                           ------------      ------------      ------------
Net income (loss) applicable to common shares              $    535,001      $  1,441,773      $  7,156,096
                                                           ============      ============      ============

Net income (loss) per share - before cumulative effect     $        .09      $        .19      $        .81
Cumulative effect                                                  (.01)             --                --
                                                           ------------      ------------      ------------
Net income (loss) per share - basic and diluted            $        .08      $        .19      $        .79
                                                           ============      ============      ============

Weighted average common shares - basic                        6,560,000         7,396,880         8,797,529
Weighted average common shares - diluted                      6,560,000         7,491,778         9,102,181

STATEMENT OF CASH FLOWS DATA:
Cash provided by (used in) operating activities            $  1,014,290      $  3,684,155      $ 16,323,103
Cash provided by (used in) investing activities                 464,315        (8,867,944)      (39,549,002)
Cash provided by (used in) financing activities              (1,385,000)        5,418,813        24,755,850

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net                                $ 27,660,317      $ 35,956,760      $ 58,927,397
Total assets                                                 31,501,206        40,991,463        81,103,271
Long-term debt, including current portion                     6,690,000         3,762,294         1,756,002
Shareholders' equity                                         22,618,565        32,406,856        61,225,096
</TABLE>

                                       24
<PAGE>

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.

<TABLE><CAPTION>
                                                                               YEAR ENDED DECEMBER 31,
                                                                      ----------------------------------------
                                                                         2003           2004           2005
                                                                      ----------     ----------     ----------
<S>                                                                           <C>            <C>            <C>
PRODUCTION:
Oil (MBbls)                                                                   35             30             48
Natural gas (MMcf)                                                           917          1,049          1,930
Gas equivalent (MMcfe)                                                     1,124          1,231          2,220

AVERAGE SALES PRICE:
Oil (per Bbl)                                                         $    30.41     $    40.83     $    53.35
Natural gas (per Mcf)                                                       4.73 (1)       6.15           8.52

AVERAGE SALES PRICE (PER MCFE)                                        $     4.79     $     6.25     $     8.57

OPERATING AND OVERHEAD COSTS (PER MCFE):
Lease operating expenses                                              $      .74     $     1.03     $      .93
Production and severance taxes                                               .34            .42            .56
General and administrative                                                  1.40           1.61           1.53
                                                                      ----------     ----------     ----------
                        Total                                         $     2.48     $     3.06     $     3.02
                                                                      ----------     ----------     ----------

OPERATING MARGIN (PER MCFE)                                           $     2.31     $     3.19     $     5.55

OTHER (PER MCFE):
Depreciation, depletion and amortization - oil and gas production     $     1.08     $     1.28     $     1.58


ESTIMATED NET PROVED RESERVES (AS OF PERIOD-END):
Natural gas (Bcf)                                                           45.0           56.9          150.2
Oil (MMbls)                                                                  1.3            1.2            2.0
Total (Bcfe)                                                                53.0           64.3          162.0
Estimated Future Net Revenues ($MM)(2)(3)                             $    178.3     $    214.3     $  1,648.9
Present Value ($MM)(2)(3)                                             $     71.2     $     83.2     $    409.6
Standardized measure of discounted future net cash flows ($MM)(4)     $     48.0     $     64.2     $    302.4
</TABLE>

-----------------------------

(1)  Net of results of hedging activities which reduced the average gas price in
     2003 $.48 per Mcf.

(2)  See "Item 1 - Certain Technical Terms."

(3)  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."

                                       25
<PAGE>

(4)  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 K - Supplemental Information on Oil and Gas
     Operations."

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. All of our reserve estimates are prepared by
Sproule Associates, Inc.

            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

                                       26
<PAGE>

no assurance that significant revisions will not be necessary in the future. If
future significant revisions are necessary that reduce previously estimated
reserve quantities, it could result in a full cost property writedown. In
addition to the impact of the estimates of proved reserves on the calculation of
the ceiling, estimates of proved reserves are also a significant component of
the calculation of the full cost pool amortization.

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

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

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

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

ASSET RETIREMENT OBLIGATIONS

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

                                       27
<PAGE>

Increases in the ARO liability due to passage of time impact net income as an
accretion expense. The related capitalized cost, including revisions thereto, is
charged to expense through DD&A. At December 31, 2005, the Company's balance
sheet included an estimated liability for ARO of $2,212,233.

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, 2005,
we estimated that our deferred tax liabilities were $1,212,100.

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 92% 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 $6.25 in the
year of 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 to operate new wells. Lease
operations expense on an equivalent unit of production basis was $.93 per Mcfe
in 2005 compared to $1.09 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 $1.79 per Mcfe in 2005 compared to

                                       28
<PAGE>

$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 increases in staff necessary
to operate at higher levels of drilling and production. General and
administrative expense per equivalent unit of production was $1.53 per Mcfe for
2005 compared to $1.72 per Mcfe for 2004, reflecting slightly improved
efficiency levels.

            INCOME TAXES. Income tax for 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. We expect our deferred non-cash tax provision
to be approximately 25% in 2006.

            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 basic and
fully diluted share was $0.81 in 2005 compared to $0.19 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.

RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2004 COMPARED TO THE YEAR
ENDED DECEMBER 31, 2003

            OIL AND GAS SALES. Oil and gas sales in the year ended December 31,
2004 increased 43% to $7,689,882 compared to the year ended December 31, 2003,
due to an increase of 10% in production and a 30% increase in the average oil
and gas price. The average price per barrel of oil and Mcf of gas received in
2004 was $40.83 and $6.15, respectively, compared to $30.41 and $4.73 in the
year 2003. During 2003, we hedged 180,000 Mcf of gas through price swap
agreements with a fixed price of $2.664 per Mcf. The price swap agreements
reduced sales by $438,400. Oil production for 2004 decreased 5MBbls to 30 MBbls
compared to 2003. Gas production increased to 1,049 MMcf compared to 917 MMcf
for the year of 2003, an increase of 14%. Increased production in 2004 resulted
from drilling and recompleting new wells during the year.

            LEASE OPERATIONS. Lease operations expense increased $411,075 in
2004 to $1,261,109, to 48% increase compared to 2003. 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 $1.02 per
Mcfe in 2004 compared to $.74 per Mcfe for 2003, resulting from re-works and
maintenance to enhance production.

            PRODUCTION AND SEVERANCE TAXES. Production and severance taxes
increased 22% to $518,721 in 2004 compared to $384,069 in 2003. Production and
severance taxes are assessed on the value of the oil and gas produced prior to
the effect of price swap agreements. As a result, the increased resulted
primarily from the increase in oil and gas sales prices and an increase in
production.

                                       29
<PAGE>

            DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation depletion and
amortization expense increased $494,071 to $2,043,485 in 2004, up 32% from 2003.
This increase is due primarily to an increase in production for 2004. The oil
and gas depreciation, depletion and amortization rate per equivalent unit of
production was $1.28 per Mcfe in 2004 compared to $1.08 per Mcfe in 2003.

            INTEREST. Interest expense for 2004 was $558,504 compared to
$439,313 for 2003. This increase is primarily attributable to a higher cost of
subordinated debt in the first six months of 2004.

            GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative
expense for 2004 was $1,985,913 compared to $1,578,865 for 2003, an increase of
26%. This increase for $407,048 was the result of an increase in salaries and
payroll expense of $215,000 from personnel additions, an increase of $64,000 in
cost of being public and an $85,000 increase in technical consulting costs.
General and administrative expense per equivalent unit of production was $1.65
per Mcfe for 2004 compared to $1.40 per Mcfe for 2003.

            INCOME TAXES. Income tax for year of 2004 was $24,206 as compared to
zero in 2003.

            NET INCOME AND NET INCOME PER SHARE. For 2004, we reported net
income of $1,441,773 compared to $535,000 for 2003. Net income per basic and
fully diluted share was $0.19 in 2004 compared to $0.08 in 2003, up 138%, while
weighted average fully-diluted shares outstanding increased by 14% from
6,560,000 to 7,491,778.

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, 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. We received a net $24,755,850 in cash from financing activities in
2005 compared to 2004 amounts of $5,418,513. The cash flow from financing
activities in 2005 was primarily from the sale of common stock of $21,662,143
and additional debt. The cash inflow in 2004 from financing activities primarily
resulted from the sale of common stock of $8,346,518 and re-payment of debt.

            CASH FLOW--YEAR ENDED DECEMBER 31, 2004 COMPARED TO YEAR ENDED
DECEMBER 31, 2003. In 2004 we had a positive cash flow from operating activities
of $3,684,155 as a result of increased production and higher oil and gas prices
during 2004. Our cash flow from operating activities in 2003 was $1,014,290. We
expended $8,902,267 on capital expenditures in 2004, primarily on drilling and
development costs, compared to receiving a net $464,315 in 2003 after a sale of
properties. The cash inflow in 2003 was primarily from the year-end agreement

                                       30
<PAGE>

with PVOG. The net cash inflow in 2004 of $5,418,813 from financing activities
primarily resulted from sales of common stock in the amount of $8,346,518,
offset by repayment of debt.

CREDIT FACILITY

            In July 2005, we executed a loan agreement with Hibernia National
Bank ("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 initial
Borrowing Base was established at $17 million and will be re-determined at least
semi-annually on or about April 1 and October 1 of each year. On December 1,
2005 the Borrowing Base was re-determined to $24 million. The loan bears
interest at the rate elected by us of either the prime rate as published in the
Wall Street Journal (payable monthly) or the LIBO rate plus a margin ranging
from 1.5% to 2.25% based on the amount of the loan outstanding in relation to
the Borrowing Base for a period of one, two or three months (payable at the end
of such period). Principal is payable voluntarily by us or is required to be
paid (i) if the loan amount exceeds the Borrowing Base; (ii) if the Lender
elects to require periodic payments as a part of a Borrowing Base
re-determination; and (ii) at the maturity date of July 29, 2008. In connection
with the December 1, 2005 borrowing base redetermination, the Borrowing Base is
subject to a mandatory borrowing base reduction of $1.5 million per quarter. We
are obligated to pay a facility fee equal to 0.25% per year of the unused
portion of the Borrowing Base payable quarterly. 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 $28.9 million adjusted annually
                to add 50% of our net income for the prior fiscal year;

            3.  Maintain on a quarterly basis a ratio of EBITDA to interest
                expense 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;

            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;

                                       31
<PAGE>

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

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

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

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

            As of December 31, 2005, we had $1,000 outstanding under the
facility.

OTHER 2005 FINANCINGS AND 2006 WARRANT EXERCISES

            COMMON STOCK PRIVATE PLACEMENT. In July 2005, we completed a private
placement and sold 1,600,000 shares of common stock for $21,600,000. Proceeds of
these have been used for general corporate purposes, primarily drilling in our
East Texas properties. 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. Subsequent to year end, we received $14 million in warrant exercise
proceeds and issued an additional 1,164,402 shares of common stock.


WORKING CAPITAL

            At December 31, 2005, we had a working capital deficit of
$7,103,835. Including availability under our credit facility, our working
capital as of December 31, 2005 would have been $16,896,165. Total rig note and
PVOG financing debt outstanding at December 31, 2005 was $6.86 million,
representing 11.1% of our total capitalization.




                                       32
<PAGE>

COMMITMENTS AND CAPITAL EXPENDITURES

            The following table reflects the Company's contractual obligations
as of December 31, 2005.

<TABLE><CAPTION>
                                                                Payments Due by Period
                                    --------------------------------------------------------------------------------
                                                     Less than 1                           3-5          More than 5
  Contractual Obligations               Total           year            1-3 years         years            years
-------------------------------     ------------     ------------     ------------     ------------     ------------
<S>                                 <C>              <C>              <C>              <C>             <C>

Long-term debt                      $      1,000     $       --              1,000     $       --       $       --
Operating leases                         225,115          118,522          106,593             --               --
75% PVOG Financing(1)                  1,755,002          345,967          566,812          384,527          457,696
First Rig - Purchase Note((2))         5,100,000        5,100,000             --               --               --
Second Rig - Assembly Cost((2))        3,173,517        3,173,517             --               --               --
                                    ------------     ------------     ------------     ------------     ------------
Total                               $ 10,254,634     $  8,737,006     $  1,516,628     $    384,527          457,696
                                    ============     ============     ============     ============     ============
</TABLE>

-----------------------------

(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.

(2)   The first rig purchase note was paid on January 2, 2006. The second rig
      assembly cost represents an estimate of the remaining costs pursuant to an
      agreement providing for assembly on a cost plus basis, but we can
      terminate this agreement at any time.

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

LIQUIDITY AND FINANCING CONSIDERATIONS

            We have projected capital expenditures in 2006 ranging from $72 to
$93 million. We expect production from our wells drilled and completed in 2004
and 2005 to provide cash flow to support additional drilling in 2006 and beyond.
Our 2005 cash flow was significantly greater than 2004. In addition, we will
have availability under our credit facility ($22 million as of March 13, 2006
based on the last Borrowing Base determination of $24 million effective as of
December 1, 2005) and expect that increases in the Borrowing Base may occur
during the year as additional production is established. Also, we received
approximately $14 million in cash from exercise of warrants in 2006. As a
result, we believe we could fund from these sources from $66 to $72 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

                                       33
<PAGE>

drilling funds or debt placements. We do not anticipate issuing additional
common stock in 2006 to fund drilling.

PRICE RISK MANAGEMENT

            In the past, we have entered into financial price risk management
activities with respect to a portion of projected oil and gas production through
financial price swaps whereby we received a fixed price for our production and
pay a variable market price to the contract counterparty. These activities are
intended to reduce our exposure to oil and gas price fluctuations. We may enter
into these instruments when we believe forward market conditions are relatively
favorable. 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 2006. The gains and
losses realized as a result of these activities are substantially offset in the
cash market when the commodity is delivered.

EFFECT OF ACCOUNTING STANDARDS

            In December 2004, the FASB issued Statement on Financial Accounting
Standards No. 123 (Revised 2004), "Share-Based Payment," revising FASB Statement
123, "Accounting for Stock-Based Compensation" and superseding APB Opinion No.
25, "Accounting for Stock Issued to Employees." This statement requires a public
entity to measure the cost of services provided by employees and directors
received in exchange for an award of equity instruments, including stock
options, at a grant-date fair value. The fair value cost is then recognized over
the period that services are provided. FAS 123 (Revised 2004) is effective for
annual periods that begin after September 15, 2005 and will be adopted by the
Company in the first quarter of 2006. See Note A of our financial statements for
a disclosure of the approximate effect on net income and earnings per share for
the years 2004 and 2005 if we had applied the fair value recognition provisions
of FAS 123 to stock-based employee compensation.

            The FASB issued Statement on Financial Accounting Standards No. 153,
"Exchanges of Productive Assets," in December 2004 that amended APB Opinion No.
29, "Accounting for Nonmonetary Transactions." FAS 153 requires that nonmonetary
exchanges of similar productive assets are to be accounted for at fair value.
Previously these transactions were accounted for at book value of the assets.
This statement is effective for nonmonetary transactions occurring in fiscal
periods beginning after June 15, 2005. The adoption of this statement has not
had a material impact on our results of operations or financial condition.

            On June 1, 2005, the FASB issued SFAS Statement No. 154, "Accounting
Changes and Error Corrections" (SFAS No. 154), which will require entities that
voluntarily make a change in accounting principle to apply that change
retrospectively to prior periods' financial statements, unless this would be
impracticable. SFAS No. 154 supersedes Accounting Principles Board Opinion No.
20, "Accounting Changes' (APB 20), which previously required that most voluntary
changes in accounting principle be recognized by including in the current
period's net income the cumulative effect of changing to the new accounting
principle. SFAS No. 154 also makes a distinction between "retrospective
application" of an accounting principle and the "restatement" of financial
statements to reflect the correction of an error.

                                       34
<PAGE>

            Another significant change in practice under SFAS no. 154 will be
that if an entity changes its method of depreciation, amortization, or depletion
for long-lived, non-financial assets, the change must be accounted for as a
change in accounting estimate. Under APB 20, such a change would have been
reported as a change in accounting principle. SFAS No. 154 applies to accounting
changes and error corrections that are made in fiscal years beginning after
December 15, 2005. We do not anticipate any material impact from implementation
of this accounting standard.

FORWARD-LOOKING STATEMENTS

            All statements made in this document and accompanying supplements
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," "plans," "estimates,"
"projects" or similar expressions or statements that events "will" 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. These are described below.

RISKS RELATED TO GMX

OUR PRINCIPAL SHAREHOLDERS OWN A SIGNIFICANT AMOUNT OF COMMON STOCK, GIVING THEM
SIGNIFICANT INFLUENCE OVER CORPORATE TRANSACTIONS AND OTHER MATTERS.

            Ken L. Kenworthy, Jr. (and his wife) and Ken L. Kenworthy, Sr.
beneficially own approximately 13.9% and 7.8% 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 makes it unlikely that any
other holder or

                                       35
<PAGE>

group of holders of common stock will be able to affect the way we are managed
or the direction of our business. These factors may also delay or prevent a
change in the management or voting control of GMX.

THE LOSS OF OUR PRESIDENT OR OTHER KEY PERSONNEL COULD ADVERSELY AFFECT US.

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

WE ARE MANAGED BY THE MEMBERS OF A SINGLE FAMILY, GIVING THEM INFLUENCE AND
CONTROL IN CORPORATE TRANSACTIONS AND THEIR INTERESTS MAY DIFFER FROM THOSE OF
OTHER SHAREHOLDERS.

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

OUR WELLS PRODUCE OIL AND GAS AT A RELATIVELY SLOW RATE.

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

OUR FUTURE PERFORMANCE DEPENDS UPON OUR ABILITY TO OBTAIN CAPITAL TO FIND OR
ACQUIRE ADDITIONAL OIL AND NATURAL GAS RESERVES THAT ARE ECONOMICALLY
RECOVERABLE.

            Unless we successfully replace the reserves that we produce, our
reserves will decline, resulting eventually in a decrease in oil and natural gas
production and lower revenues and cash flows from operations. The business of
exploring for, developing or acquiring reserves is capital intensive. Our
ability to make the necessary capital investment to maintain or expand our oil
and natural gas reserves is limited by our relatively small size. Further, our
East Texas joint development partner, PVOG, may propose drilling that would
require more capital than we have available from cash flow from operations or
our bank credit facility. In such case, we would be required to seek additional
sources of financing or limit our participation in the additional

                                       36
<PAGE>

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 in the foreseeable future. Payment
of any future dividends 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 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.

            Although we do not currently plan to hedge any of our production, we
may enter into hedging arrangements in the future or if required by our bank
credit facility. Hedging arrangements expose us to risk of financial loss in
some circumstances, including the following:

            o production is less than expected;

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

            o 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
engage in hedging arrangements.

OUR CREDIT FACILITY CONTAINS CERTAIN COVENANTS THAT MAY INHIBIT OUR ABILITY TO
MAKE CERTAIN INVESTMENTS, INCUR ADDITIONAL INDEBTEDNESS AND ENGAGE IN CERTAIN
OTHER TRANSACTIONS, WHICH COULD ADVERSELY AFFECT OUR ABILITY TO MEET OUR FUTURE
GOALS.

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

            o our investments, loans and advances and the paying of dividends
              and other restricted payments;

            o our incurrence of additional indebtedness;

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

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

                                       37
<PAGE>

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

            o the sale of assets; and

            o our capital expenditures.

            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 begun the process of evaluating our internal controls
systems to allow management to report on, and our independent auditors to audit,
our internal controls over financial reporting. We will be performing the system
and process evaluation and testing (and any necessary remediation) required to
comply with the management certification and auditor attestation requirements of
Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply
with Section 404 for the year ending December 31, 2006. However, we cannot be
certain as to the timing of completion of our evaluation, testing and
remediation actions or the impact of the same on our operations. Furthermore,
upon completion of this process, we may identify control deficiencies of varying
degrees of severity under applicable SEC and Public Company Accounting Oversight
Board rules and regulations that remain unremediated. As a public company, we
will be required to report, among other things, control deficiencies that
constitute a "material weakness" or changes in internal controls that, or that
are reasonable likely to, materially affect internal controls over financial
reporting. A "material weakness" is a significant deficiency or combination of
significant deficiencies that results in more than a remote likelihood that a
material misstatement of the annual or interim consolidated financial statements
will not be prevented or detected. If we fail to implement the requirements of
Section 404 in a timely manner, we might be subject to sanctions or
investigation by regulatory authorities such as the SEC. In addition, 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.

                                       38
<PAGE>

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:

            o worldwide and domestic supplies of oil and gas;

            o weather conditions;

            o the level of consumer demand;

            o the price and availability of alternative fuels;

            o the availability of pipeline capacity;

            o the price and level of foreign imports;

            o domestic and foreign governmental regulations and taxes;

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

                                       39
<PAGE>

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

            o 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 93% of our reserves at
December 31, 2005 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 2005, 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 Securities and Exchange
Commission, and are inherently imprecise. Actual future production, cash flows,
taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from our
estimates. Also, the use of a 10% discount factor for reporting purposes may not
necessarily represent the most appropriate discount factor, given actual
interest rates and risks to which our business or the oil and natural gas
industry in general are subject.

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

                                       40
<PAGE>

            At December 31, 2005, approximately 72% 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 $190 million to develop these reserves, including $109 million
in 2006. You should be aware that the 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:

            o the presence of unanticipated pressure or irregularities in
              formations;

            o accidents;

            o title problems;

            o weather conditions;

            o compliance with governmental requirements; and

            o shortages or delays in the delivery of equipment.

            Also, our ability to market oil and natural gas production depends
upon numerous factors, many of which are beyond our control, including:

            o capacity and availability of oil and natural gas systems and
              pipelines;

            o effect of federal and state production and transportation
              regulations; and

                                       41
<PAGE>

            o changes in supply of and demand for oil and natural gas.

WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE MATERIALLY IMPACTED
BY UNINSURED LOSSES.

            Our operations are subject to the risks inherent in the oil and
natural gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents, such as
oil spills, gas leaks, salt water spills and leaks, ruptures or discharges of
toxic gases. If any of these risks occur in our operations, we could experience
substantial losses due to:

            o injury or loss of life;

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

            o pollution or other environmental damage;

            o clean-up responsibilities;

            o regulatory investigation and penalties; and

            o 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 limit of $2 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

                                       42
<PAGE>

governmental fines. We could potentially discharge these materials into the
environment in any of the following ways:

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

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

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

            o blowouts, cratering and explosions.

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

COMPETITION IN THE OIL AND GAS INDUSTRY IS INTENSE, AND WE ARE SMALLER THAN MANY
OF OUR COMPETITORS.

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

ITEM 7.       FINANCIAL STATEMENTS

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

ITEM 8.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
              FINANCIAL DISCLOSURE

            None.

ITEM 8A.      CONTROLS AND PROCEDURES

            Our Principal Executive Officer and Principal Financial Officer have
reviewed and evaluated the effectiveness of our disclosure controls and
procedures (as defined in Exchange Act Rule 240.13a-14(c)) as of the end of the
period covered by this report. Based on that evaluation, the Principal Executive
Officer and the Principal Financial Officer have concluded that our current
disclosure controls and procedures are effective to ensure that information
required to be disclosed in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms.

ITEM 8B.      OTHER INFORMATION

            None.

                                       43
<PAGE>

                                    PART III

ITEM 9.       DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
              COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

DIRECTORS AND EXECUTIVE OFFICERS

            The directors and executive officers of the Company are as follows:

NAME                             AGE       POSITION CURRENTLY HELD
-----------------------------    ---       -----------------------------------
Ken L. Kenworthy, Jr.             49       President, Chief Executive Officer
                                           and Director
Ken L. Kenworthy, Sr.             70       Executive Vice President, Secretary,
                                           Treasurer, Chief Financial Officer
                                           and Director
T.J. Boismier                     71       Director
Steven Craig                      49       Director
Jon W. "Tucker" McHugh            61       Director
Gary D. Jackson                   55       Vice President - Land

            The following is a brief description of the business background of
each of our directors and executive officers.

            KEN L. KENWORTHY, JR. is a co-founder of GMX and has been President
and a director since the Company's inception in 1998. In 1980, he founded OEXCO
Inc., a privately held oil and gas company, which he managed until 1995 when its
properties were sold for approximately $13 million. During this period OEXCO
operated 300 wells and drilled and discovered seven fields and dozens of new
zones. During this same period, he formed and managed a small gas gathering
system. From 1995 until he founded GMX in 1998, Mr. Kenworthy was a private
investor. From 1980 to 1984, he was a partner in Hunt-Kenworthy Exploration
which was formed to share drilling and exploration opportunities in different
geological regions. Prior to 1980, he held various geology positions with Lone
Star Exploration, Cities Service Gas Co., Nova Energy, and Berry Petroleum
Corporation. He also served as a director of Nichols Hills Bank, a commercial
bank in Oklahoma City, Oklahoma for ten years before it was sold in 1996 to what
is now Bank of America. He is a member of the American Association of Petroleum
Geologists and Oklahoma City Geological Society.

            KEN L. KENWORTHY, SR. is a co-founder of GMX and has been Executive
Vice President, Chief Financial Officer and a director since the Company's
inception in 1998. From 1993 to 1998, he was principal owner and Chairman of
Granita Sales Inc., a privately-held frozen beverage manufacturing distribution
company. Prior to that time, he held various financial positions with private
and public businesses, including from 1970 to 1984, as vice president,
secretary-treasurer, chief financial officer and a director of CMI Corporation,
a New York Stock Exchange listed company which manufactures and sells
road-building equipment. He has held several accounting industry positions
including past president of the Oklahoma City Chapter National Association of
Accountants, past vice president of the National Association of Accountants and
past officer and director of the Financial Executives Institute.

            T. J. BOISMIER is founder, President and Chief Executive Officer of
T. J. Boismier Co., Inc., a privately held mechanical contracting company in
Oklahoma City, Oklahoma, which designs and installs plumbing, heating, air
conditioning and utility systems in commercial

                                       44
<PAGE>

buildings, a position he has held since 1961. He became a director in February
2001 simultaneously with the completion of the Company's initial public
offering.

            STEVEN CRAIG is the Chief Energy Analyst for Elliott Wave
International, a securities market research and advisory company located in
Gainesville, Georgia, which is one of the world's largest providers of market
research and technical analysis. As Chief Energy Analyst, Mr. Craig provides
in-depth analysis and price forecasts of the major NYMEX energy markets to an
institutional clientele that spans the gamut of the energy industry. Prior to
joining Elliott Wave International in January 2001, he provided risk management
services to Central and South West, one of the largest natural gas consumers in
the U.S. prior to its merger with American Electric Power in June 2000 and
independent oil and gas producer Kerr-McGee. He became a director in August
2001.

            GARY D. JACKSON became Vice President of Land for the Company in
2005. During 2004 and 2005 prior to joining the Company, he was an independent
petroleum landman, performing and directing contract land services for other oil
and gas companies for CLS Group, Edmond, OK Prior to that time, he was President
of for SAI Consulting, which provided professional services for oil and gas and
natural resources asset acquisition and management.

             JON W. "TUCKER" MCHUGH became a director of the Company in January
2005. Since 1997, Mr. McHugh has been Senior Vice President Commercial Lending
and head of marketing at First Commercial Bank, Edmond, Oklahoma.

            Ken Kenworthy, Sr. is the father of Ken Kenworthy, Jr.

SIGNIFICANT EMPLOYEES

            Keith Leffel, age 56, has been employed as our natural gas marketer
and pipeline operations manager since November 2001. Since 1986, Mr. Leffel
formed and operated GKL Energy Services Company, a company that assists
producers with gas marketing services.

            Rick Hart, Jr. a, petroleum engineer, age 48, was hired in January
2004 as Operations Manager. He has 24 years of experience in all aspects of
operations, including specific expertise in drilling, completion and production
in the East Texas reservoirs. Immediately before coming to work for GMX, he
worked with Focus Energy for nine years and had responsibility for 319 producing
wells.

TERMS

            Each director is elected to hold office until the next annual
meeting of shareholders or until his successor is duly elected and qualified.
The executive officers and significant employees are appointed by the Board of
Directors and serve at its discretion.

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

            Section 16(a) of the Securities and Exchange Act of 1934 requires
our directors and executive officers and persons who beneficially own more than
10% of our common stock to file reports of ownership and changes in ownership of
our common stock with the Securities and

                                       45
<PAGE>

Exchange Commission. We are required to disclose delinquent filings of reports
by such persons.

            Based on a review of the copies of such reports and amendments
thereto received by us, or written representations that no filings were
required, we believe that all Section 16(a) filing requirements applicable to
our executive officers, directors and 10% shareholders were met during 2005,
except as follows: (i) Steven Craig filed a late Form 4 on September 7, 2005
relating to exercises of options and sale of 800 shares on August 31, 2005, 200
shares on September 1, 2005, and 500 shares on September 2, 2005; (ii) Kyle
Kenworthy filed a late Form 4 on April 26, 2005, relating to the grant of an
option for 5,000 shares on September 10, 2001; (iii) Kyle Kenworthy filed a late
Form 4 on April 26, 2005, relating to the exercise of options to purchase 10,000
shares, 5,000 shares and 3,750 shares and the sale of 12,931 shares, all on
April 21, 2005; and (iv) Jon McHugh filed a late Form 5 on February 27, 2006,
relating to the purchase of 500 shares on November 10, 2005.

AUDIT COMMITTEE MATTERS

            During 2005, we had a standing audit committee consisting of Messrs.
McHugh, Boismier and Craig, all of whom have been determined by the Board to be
independent as required by applicable rules of the Securities and Exchange
Commission and The NASDAQ Stock Market. In January 2005, Mr. McHugh was elected
to the Board and the audit committee. The Board has determined that Mr. McHugh
is independent as required by applicable rules of the Securities and Exchange
Commission and The NASDAQ Stock Market and qualifies as a "financial expert."

CODE OF ETHICS

            We have adopted a Code of Business Conduct and Ethics ("Code") that
is applicable to all of our officers, directors and employees, including our
principal executive, financial and accounting officers. A copy of the Code is
filed as an exhibit to this report.



                                       46
<PAGE>

ITEM 10.                EXECUTIVE COMPENSATION

            The following table sets forth information with respect to
compensation received by our chief executive officer and our other executive
officers.

SUMMARY COMPENSATION TABLE
<TABLE><CAPTION>
                                                                        ANNUAL COMPENSATION
                                                              --------------------------------------------
                                                                                              OTHER ANNUAL      ALL OTHER
NAME AND PRINCIPAL POSITION                      YEAR          SALARY            BONUS        COMPENSATION    COMPENSATION(1)
---------------------------                      ----          ------            -----        ------------    ---------------
<S>                                              <C>           <C>              <C>            <C>              <C>
Ken L. Kenworthy, Jr                             2003         $157,500         $   --           $   --           $   --
    President and Chief Executive                2004          166,667           20,000             --               --
    Officer                                      2005          175,000           50,000             --             10,365

Ken L. Kenworthy, Sr                             2003          157,500             --               --               --
    Executive Vice President, Secretary,
   Treasurer and Chief Financial Officer         2004          166,667           20,000             --               --
                                                 2005          175,000           50,000             --             10,750

Gary D. Jackson                                  2005           38,333            6,000             --              2,304
    Vice President--Land
</TABLE>

(1)   All Other Compensation includes amounts contributed by GMX for the account
      of the named individual to GMX'S 401(k) plan and a gasoline allowance for
      Gary Jackson.The following table shows option grants to the named
      executive officers in 2005.

            On March 29, 2006, the Compensation Committee of the Board approved
increases in salaries for Mssrs. Kenworthy, Jr. and Kenworthy Sr. to $225,000
per year for calendar year 2006.

                        OPTION GRANTS IN LAST FISCAL YEAR
<TABLE><CAPTION>

                               NUMBER OF SHARES OF           % OF TOTAL OPTIONS
                              COMMON STOCK UNDERLYING        GRANTED TO EMPLOYEES    EXERCISE OR BASE PRICE
             NAME                 OPTIONS GRANTED               IN FISCAL YEAR           ($/SHARE) (1)          EXPIRATION DATE
             ----                 ---------------               --------------           -------------          ---------------
<S>                               <C>                           <C>                      <C>                    <C>
Gary D. Jackson                       25,000                         18.2%                  $ 20.01                9-15-2015
</TABLE>

--------------------

(1)   These options became exercisable at the rate of 25% per year as long as
      the optionee remains employed.

            The following table reflects options exercised during 2005 or
outstanding at year-end for the named executive officers.

                                       47
<PAGE>

<TABLE><CAPTION>
                   AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES

                                                              NUMBER OF SECURITIES                         VALUE OF
                                                             UNDERLYING UNEXERCISED                UNEXERCISED IN-THE-MONEY
                                                                 OPTIONS AT                                OPTIONS AT
                          SHARES                              DECEMBER 31, 2005                        DECEMBER 31, 2005
                         ACQUIRED          VALUE        --------------------------------         ------------------------------
NAME                    ON EXERCISE       REALIZED      EXERCISABLE        UNEXERCISABLE         EXERCISABLE      UNEXERCISABLE
----                    -----------       --------      -----------        -------------         -----------      -------------
<S>                     <C>               <C>           <C>                <C>                   <C>              <C>

Gary D. Jackson           N/A                N/A           -----              25,000                 -----           $399,750
</TABLE>

COMPENSATION OF DIRECTORS

            Nonemployee directors, T. J. Boismier, Steven Craig and Jon Tucker
McHugh receive $1,500 for each board of directors meeting, $1,000 for each audit
committee meeting, $500 for each compensation and nominating committee. In
addition, the chairman and secretary of the audit committee receive $250 and
$200, respectively, for each audit committee meeting which they attend. Board
members are also eligible to receive stock options. None were granted in 2005
other than to Mr. McHugh, who received an option for 10,000 shares at $8.00 per
share on the date he was elected a director, January 20, 2005.

ITEM 11.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
              RELATED STOCKHOLDER MATTERS

            The following table sets forth certain information regarding the
beneficial ownership of our common stock as of March 29, 2006, by (i) each of
our directors; (ii) each of our executive officers and the spouse of our Chief
Executive Officer; and (iii) all of our directors and executive officers as a
group.

            As of March 29, 2006, there were 11,192,467 shares of common stock
outstanding. Except as otherwise listed below, each named beneficial owner has
sole voting and investment power with respect to the shares listed.

<TABLE><CAPTION>
                                                                       NUMBER         PERCENT
BENEFICIAL OWNER                                                      OF SHARES       OF TOTAL
----------------                                                      ---------       --------
<S>                                                                   <C>             <C>
Ken L. Kenworthy, Jr. (1) (2) ...................................       848,471           7.6%
Karen Kenworthy(2)(6) ...........................................       710,918           6.4%
Ken L. Kenworthy, Sr.(2) ........................................       868,324           7.8%
T. J. Boismier (3) ..............................................        22,500             *
Steven Craig(4) .................................................         7,500             *
Gary D. Jackson .................................................                           *
Jon W. McHugh(5) ................................................         3,500             *
All executive officers and directors as a group (6 persons) .....     2,461,213          22.0%
</TABLE>

---------------------------
      * Less than 1%.

(1)   Shares owned by Mr. Kenworthy, Jr. exclude 710,918 shares owned by his
      wife as to which he disclaims beneficial ownership.

(2)   The business address of Messrs. Kenworthy, Jr. and Kenworthy, Sr. and
      Karen M. Kenworthy is 9400 North Broadway, Oklahoma City, Oklahoma 73114.

(3)   Includes 22,500 shares Mr. Boismier has the right to acquire on exercise
      of options exercisable within 60 days.

                                       48
<PAGE>

(4)   Includes 7,500 shares which Mr. Craig has the right to acquire on exercise
      of options exercisable within 60 days.

(5)   Includes 2,500 shares which Mr. McHugh has the right to acquire on
      exercise of options exercisable within 60 days.

(6)   Shares owned by Karen Kenworthy exclude 848,471 shares owned by her
      husband Ken L. Kenworthy, Jr., as to which she disclaims beneficial
      ownership.

            The following table sets forth certain information regarding the
beneficial ownership of our common stock as of December 31, 2005 by persons
known to beneficially own more than 5% of our outstanding stock on December 31,
2005. This information is based on filings made by such persons with the
Securities & Exchange Commission. Except as otherwise indicated, each beneficial
owner has sole voting and investment power with respect to the shares voted.

<TABLE><CAPTION>
                                                                       NUMBER         PERCENT
BENEFICIAL OWNER                                                      OF SHARES       OF TOTAL
----------------                                                      ---------       --------
<S>                                                                   <C>             <C>
Newton Family Group (1) ............................................    900,000           8.0%
JANA Partners LLC(2) ...............................................    558,016           5.5%
Morgan Stanley and Morgan Stanley Investment
Management, Inc. (3) ...............................................    528,500           5.7%
</TABLE>

(1)   The Newton Family Group consists of William C. Newton and Gloria A.
      Newton, husband and wife, and Newton Investment Partners, as to which
      William C. Newton is the managing partner. William C. Newton and Gloria A.
      Newton have beneficial ownership of 900,000 shares, which includes 875,000
      shares beneficially owned by Newton Investment Partners. The business
      address of the Newton Family Group is c/o Notwen Corporation, 660 East
      Broadway, Jackson Hole, Wyoming 83001.

(2)   JANA Partners LLC is a private money management firm which holds the
      common stock in various accounts under its management and control. Its
      address is 200 Park Avenue, Suite 3300, New York, NY 10166.

(3)   Morgan Stanley Investment Management, Inc. is a wholly owned subsidiary of
      Morgan Stanley and holds common stock in various discretionary accounts
      which it manages. The address of Morgan Stanley is 1585 Broadway, New
      York, NY 10036, and of Morgan Stanley Investment Management, the address
      is 1221 Avenue of the Americas, New York NY 10020.

ITEM 12.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

            None.

ITEM 13.      EXHIBITS

            For a list of Exhibits, see the Exhibit Index immediately preceding
the Exhibits filed with this report.

                                       49
<PAGE>

ITEM 14.      PRINCIPAL ACCOUNTANT FEES AND SERVICES

            The following table sets forth the fees billed by our independent
auditor, Smith, Carney & Co., p.c. for 2004 and 2005:


                                                       FEES BILLED
                                                  ----------------------
                    TYPE                             2004        2005
                    ----                          ----------  ----------
          Audit fees                              $   50,000  $   54,168
          Audit related fees                            --          --
          Tax fees                                    15,000      15,000

          All other fees                               9,505      14,763
                                                  ----------  ----------
               Total                              $   74,505  $   83,931
                                                  ==========  ==========

            The Audit Committee pre-approved all audit and non-audit services,
if any, performed by our independent auditors. All other fees in 2004 and 2005
related to non-prohibited consulting services provided by our independent
auditors in 2004.
















                                       50
<PAGE>

                                   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.

Dated:  March 30, 2006                 GMX RESOURCES INC.


                                       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.

<TABLE><CAPTION>
         SIGNATURES                                   TITLE                                      DATE
         ----------                                   -----                                      ----
<S>                                    <C>                                                   <C>
/s/ Ken L. Kenworthy, Jr.              President and Director                                March 30, 2006
-----------------------------------    (Principal Executive Officer)
Ken L. Kenworthy, Jr.

/s/ Ken L. Kenworthy, Jr.              Executive Vice President, Chief Financial Officer     March 30, 2006
-----------------------------------    and Director (Principal Financial and Accounting
Ken L. Kenworthy, Sr.                  Officer)

/s/ T. J. Boismier                     Director                                              March 30, 2006
-----------------------------------
T. J. Boismier

/s/ Steven Craig                       Director                                              March 30, 2006
-----------------------------------
Steven Craig

/s/ Jon W. McHugh                      Director                                              March 30, 2006
-----------------------------------
Jon W. McHugh
</TABLE>

                                       51
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm..................... F-2

Consolidated Balance Sheets, December 31, 2004 and 2005..................... F-3

Consolidated Statements of Operations, Years Ended December 31,
    2004 and 2005........................................................... F-4

Consolidated Statements of Changes in Shareholders' Equity, Years
    Ended December 31, 2004 and 2005........................................ F-5

Consolidated Statements of Cash Flows, Years Ended December 31,
    2004 and 2005........................................................... F-6

Notes to Consolidated Financial Statements.................................. F-7














                                      F-1
<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
GMX Resources Inc.

We have audited the accompanying consolidated balance sheets of GMX Resources
Inc. and subsidiaries as of December 31, 2004 and 2005 and the related
consolidated statements of operations, changes in shareholders' equity, and cash
flows for the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audit in accordance with auditing standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatements. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of GMX Resources Inc.
and subsidiaries as of December 31, 2004 and 2005 and the results of their
operations and their cash flows for the years then ended, in conformity with
U.S. generally accepted accounting principles.

                                       Smith, Carney & Co., p.c.



Oklahoma City, Oklahoma
February 16, 2006





                                      F-2
<PAGE>


                       GMX RESOURCES INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
<TABLE><CAPTION>
                                                                                                           December 31,
                                                                                                  ------------------------------
                                                                                                      2004              2005
                                                                                                  ------------      ------------
<S>                                                                                               <C>                  <C>
                                     ASSETS
CURRENT ASSETS:
         Cash and cash equivalents                                                                $    862,546         2,392,497
         Accounts receivable--interest owners                                                           96,248            74,971
         Accounts receivable--oil and gas revenues                                                   1,501,073         4,188,451
         Inventories                                                                                   204,442           247,364
         Prepaid expenses                                                                              108,447            10,028
                                                                                                  ------------      ------------
                      Total current assets                                                           2,772,756         6,913,311
                                                                                                  ------------      ------------

OIL AND GAS PROPERTIES, AT COST, BASED ON THE FULL COST METHOD OF
   ACCOUNTING                                                                                       42,452,970        68,920,264
         Less accumulated depreciation, depletion, and amortization                                 (6,496,210)       (9,992,867)
                                                                                                  ------------      ------------
                                                                                                    35,956,760        58,927,397
                                                                                                  ------------      ------------

OTHER PROPERTY AND EQUIPMENT                                                                         3,515,422        17,044,734
         Less accumulated depreciation                                                              (1,308,358)       (1,793,781)
                                                                                                  ------------      ------------
                                                                                                     2,207,064        15,250,953
                                                                                                  ------------      ------------

OTHER ASSETS                                                                                            54,883            11,610
                                                                                                  ------------      ------------

                                  TOTAL ASSETS                                                    $ 40,991,463        81,103,271
                                                                                                  ============      ============

                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
         Accounts payable                                                                         $  2,321,517         7,809,387
         Accrued expenses                                                                              134,718           419,130
         Accrued interest                                                                                 --              25,430
         Revenue distributions payable                                                                 274,862           317,232
         Short-term loan                                                                                  --           5,100,000
         Current portion of long-term debt                                                             433,933           345,967
                                                                                                  ------------      ------------
                                  Total current liabilities                                          3,165,030        14,017,146

LONG-TERM DEBT, LESS CURRENT PORTION                                                                 3,328,361         1,410,035

OTHER LIABILITIES                                                                                    2,091,216         4,450,994

SHAREHOLDERS' EQUITY:
         Preferred stock, par value $.01 per share, 500,000 shares authorized
         Common stock, par value $.001 per share-authorized 50,000,000 shares
         issued and outstanding 8,053,540 shares in 2004 and 9,975,315 shares in 2005                    8,054             9,975
         Additional paid-in capital                                                                 29,305,012        50,965,235
         Retained earnings                                                                           3,093,790        10,249,886

                                                                                                  ------------      ------------
                                  Total shareholders' equity                                        32,406,856        61,225,096
                                                                                                  ------------      ------------

                                  TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                      $ 40,991,463        81,103,271
                                                                                                  ============      ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                      F-3
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE><CAPTION>

                                                        Year Ended December 31,
                                                     -----------------------------
                                                         2004             2005
                                                     ------------     ------------
<S>                                                  <C>              <C>
REVENUE:
        Oil and gas sales                            $  7,689,882     $ 19,026,050
        Interest income                                    14,498          161,434
        Other income                                      129,330            5,220
                                                     ------------     ------------
        Total revenue                                   7,833,710       19,192,704
                                                     ------------     ------------


EXPENSES:
        Lease operations                                1,261,109        2,070,286
        Production and severance taxes                    518,721        1,241,338
        Depreciation, depletion and amortization        2,043,485        3,982,079
        Interest                                          558,504          142,409
        General and administrative                      1,985,912        3,388,396
                                                     ------------     ------------
        Total expenses                                  6,367,731       10,824,508
                                                     ------------     ------------

        Income before income taxes                      1,465,979        8,368,196

INCOME TAXES                                               24,206        1,212,100
                                                     ------------     ------------


Net income                                           $  1,441,773     $  7,156,096
                                                     ============     ============


        EARNINGS PER SHARE - Basic                   $       0.19     $       0.81
                                                     ============     ============
        EARNINGS PER SHARE -Diluted                  $       0.19     $       0.79
                                                     ============     ============
        WEIGHTED AVERAGE COMMON SHARES-Basic            7,396,880        8,797,529
                                                     ============     ============
        WEIGHTED AVERAGE COMMON SHARES-Diluted          7,491,778        9,102,181
                                                     ============     ============
</TABLE>


See accompanying notes to consolidated financial statements.

                                      F-4
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
            CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
                     YEARS ENDED DECEMBER 31, 2004 AND 2005
<TABLE><CAPTION>
                                          COMMON STOCK                 ADDITIONAL                           TOTAL
                                  ------------------------------        PAID-IN           RETAINED      SHAREHOLDERS'
                                     SHARES            AMOUNT           CAPITAL           EARNINGS          EQUITY
                                  ------------      ------------      ------------      ------------     ------------
<S>                               <C>               <C>               <C>               <C>              <C>
BALANCE AT DECEMBER 31, 2003         6,575,000      $      6,575      $ 20,959,973      $  1,652,017     $ 22,618,585
Options Exercised                       15,000                15            14,985              --             15,000
Redeemed & Cancelled Warrants             --                --            (118,712)             --           (118,712)
Warrants Granted                          --                --             257,250              --            257,250
Warrants Exercised                     163,540               164           177,398              --            177,562
Shares Issued                        1,300,000             1,300         8,014,118              --          8,015,418
Net income                                --                --                --           1,441,773        1,441,773

                                  ------------      ------------      ------------      ------------     ------------
BALANCE AT DECEMBER 31, 2004         8,053,540      $      8,054      $ 29,305,012      $  3,093,790     $ 32,406,856
                                  ------------      ------------      ------------      ------------     ------------
Options Exercised                      128,250               128           422,787              --            422,915
Redeemed & Cancelled Warrants         (144,180)             (144)         (774,134)             --           (774,278)
Warrants Granted                          --                --                --                --               --
Warrants Exercised                     337,705               337         1,666,898              --          1,667,235
Shares Issued                        1,600,000             1,600        20,344,672              --         20,346,272
Net Income                                --                --                --           7,156,096        7,156,096
                                  ------------      ------------      ------------      ------------     ------------

BALANCE AT DECEMBER 31, 2005         9,975,315      $      9,975      $ 50,965,235      $ 10,249,886     $ 61,225,096
                                  ============      ============      ============      ============     ============
</TABLE>


See accompanying notes to consolidated financial statements.

                                      F-5
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE><CAPTION>
                                                                                      YEARS ENDED DECEMBER 31,
                                                                                   ------------------------------
                                                                                       2004              2005
                                                                                   ------------      ------------
<S>                                                                                <C>               <C>
CASH FLOWS DUE TO OPERATING ACTIVITIES
        Net income                                                                 $  1,441,773      $  7,156,096
        Adjustments to reconcile net income
        to net cash provided by operating activities;
                    Depreciation, depletion, and amortization                         2,043,485         3,982,080
                    Amortization of loan fees                                           326,762           112,349
                    Deferred income taxes                                                               1,212,100
                    Decrease (increase) in:
                           Accounts receivable                                         (865,035)       (2,666,101)
                           Inventory and prepaid expenses                              (431,908)          (56,852)
                           Other assets                                                    --              43,273
                    Increase (decrease) in:
                           Accounts payable                                           1,187,017         5,487,870
                           Accrued expenses and other liabilities                        40,128           309,842
                           Revenue distributions payable                                (58,067)          742,446
                                                                                   ------------      ------------

                           Net cash provided by operating activities                  3,684,155        16,323,103
                                                                                   ------------      ------------

CASH FLOWS DUE TO INVESTING ACTIVITIES
        Additions to oil and gas properties                                          (8,533,367)      (26,019,690)
        Purchase of property and equipment                                             (334,577)      (13,529,312)
                                                                                   ------------      ------------
                        Net cash provided by (used in) investing activities          (8,867,944)      (39,549,002)
                                                                                   ------------      ------------

CASH FLOWS DUE TO FINANCING ACTIVITIES
        Advance on borrowings                                                         3,872,457        10,701,763
        Payments on debt                                                             (6,800,162)       (7,608,056)
        Proceeds from sale of stock                                                   8,346,518        21,662,143
                                                                                   ------------      ------------
                        Net cash provided by investing activities                     5,418,813        24,755,850
                                                                                   ------------      ------------

NET INCREASE IN CASH                                                                    225,024         1,529,951

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                        637,522           862,546
                                                                                   ------------      ------------

CASH AND CASH EQUIVALENTS AT END OF PERIOD                                         $    862,546         2,392,497
                                                                                   ============      ============

CASH PAID FOR INTEREST                                                             $    261,445           116,979
                                                                                   ============      ============

CASH PAID FOR INCOME TAXES                                                         $     24,206              --
                                                                                   ============      ============
</TABLE>

See accompanying notes to consolidated financial statements.

                                      F-6
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

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 Louisiana, New Mexico, and Texas.

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. Revenues
from services provided to working interest owners of properties in which GMX
also owns an interest, to the extent they exceed related costs incurred, are
accounted for as reductions of capitalized costs of oil and gas properties.

Depreciation and amortization of other property and equipment, including
leasehold improvements, are provided using the straight-line method based on
estimated useful lives from five to 10 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 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

                                      F-7
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

its undiscounted cash flows and (b) measurement of an impairment loss as the
difference between the carrying amount and fair value of the asset.

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

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

REVENUE RECOGNITION AND NATURAL GAS BALANCING: Oil and gas revenues are
recognized when sold. 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, 2004 or 2005.

CAPITALIZED INTEREST: Interest of $31,170 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.

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.

                                      F-8
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

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.

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

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

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

                                                      2004            2005
                                                  -------------   --------------
           Options excluded from dilution
             calculation                             41,000          77,000
           Range of exercise prices               $5.00 - $8.00   $20.01- $29.00
           Weighted average exercise price            $6.75           $20.98

STOCK OPTIONS: The Company applies the intrinsic value-based method of
accounting for its fixed plan stock options, as described by Accounting
Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees," and
related interpretations. As such, compensation expense would be recorded on the
date of grant only if the current market price of the underlying stock exceeded
the exercise price of the option. SFAS 123, "Accounting for Stock-Based
Compensation," established accounting and disclosure requirements using a fair
value-based method of accounting for stock-based employee compensation plans. As
allowed by Statement 123 and the rules of the SEC, GMX has elected to continue
to apply the intrinsic value based method of accounting described above through
December 31, 2005.

Stock option activity for the year ended December 31, 2004 and 2005, which
includes in 2003 shares granted to a consultant, is as follows:

                                      F-9
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

                                                              WEIGHTED
                                                NUMBER         AVERAGE
                                               OF SHARES    EXERCISE PRICE
                                              ----------      ----------
          Balance as of December 31, 2003
                                                 139,000      $     5.69
               Granted                           190,000            3.83
               Exercised                         (15,000)           1.00
               Forfeited                            --              --
               Expired                              --              --
                                              ----------      ----------
          Balance as of December 31, 2004        314,000      $     3.67
               Granted                           137,000           16.58
               Exercised                        (128,250)           2.69
               Forfeited                            --              --
               Expired                              --              --
                                              ----------      ----------
          Balance as of December 31, 2005        322,750      $     8.65
                                              ----------      ----------

At December 31, 2005, the range of exercise prices and weighted-average
remaining contractual life of outstanding options was $1.00 to $29.79 and nine
years, respectively.

At December 31, 2005, the number of options exercisable was 322,750 and the
weighted-average exercise price of those options was $8.65.

The Company applied APB Opinion No. 25 in accounting for its plan and
accordingly, no compensation cost has been recognized for its stock options
granted to employees in the financial statements. Had the Company determined
compensation cost based on the fair value at the grant date for its stock
options under Statement 123, the Company's results would have been reduced by
the pro forma amounts indicated below.

<TABLE><CAPTION>
                                                                          2004              2005
                                                                      ------------      ------------
<S>                                                                   <C>               <C>
          Net earnings as reported                                    $  1,441,773      $  7,156,096

          Add:  Stock-based compensation recognized                           --             163,379

          Deduct:  Pro forma stock-based compensation, net of tax         (316,085)         (467,085)
                                                                      ------------      ------------
          Pro forma net earnings                                      $  1,125,688      $  6,852,390
                                                                      ============      ============
          Pro forma earnings per share - basic                        $       0.15              0.78
                                                                      ============      ============
          Pro forma earnings per share - diluted                      $       0.15              0.75
                                                                      ============      ============
</TABLE>

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 10 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 10 years.

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

                                      F-10
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

interest rate of 1%, expected volatility of 144%, and an expected term of 10
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 10 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 10 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 and 2005.

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, 2003                       $    304,037
          Liabilities incurred                                        40,493
          Liabilities settled                                       (249,867)
          Accretion (1)                                               24,323
          Increase due to Revisions                                1,645,645
                                                                ------------
          Balance as of December 31, 2004                       $  1,764,631
          Liabilities incurred                                       295,756
          Liabilities settled                                       (474,603)
          Accretion (1)                                               70,585
          Increase due to revisions (2)                              555,862
                                                                ------------

          Balance as of December 31, 2005                       $  2,212,233
                                                                ============

          (1) Annual accretion is added to the full cost pool.
          (2) Revisions were due to the increase in market prices for services
          related to plugging a well, the current inflation rate and interest
          rate.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS: In December 2004, the FASB issued
Statement on Financial Accounting Standards No. 123 (Revised 2004), "Share-Based
Payment," revising FASB Statement 123, "Accounting for Stock-Based Compensation"
and superseding APB Opinion No. 25, "Accounting for Stock Issued to Employees."
This statement requires a public entity to measure the cost of services provided
by employees and directors received in exchange for an award of equity
instruments,

                                      F-11
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

including stock options, at a grant-date fair value. The fair value cost is then
recognized over the period that services are provided. FAS 123 (Revised 2004) is
effective for the first fiscal year beginning after September, 2005 and will be
adopted by the Company in the first quarter of 2006. See "Stock Options" above
for a disclosure of the effect on net income and earnings per share for the
years 2004 and 2005 if we had applied the fair value recognition provisions of
FAS 123 to stock-based employee compensation.

The FASB issued Statement on Financial Accounting Standards No. 153, "Exchanges
of Productive Assets," in December 2004 that amended APB Opinion No. 29,
"Accounting for Nonmonetary Transactions." FAS 153 requires that nonmonetary
exchanges of similar productive assets are to be accounted for at fair value.
Previously these transactions were accounted for at book value of the assets.
This statement is effective for nonmonetary transactions occurring in fiscal
periods beginning after June 15, 2005. The adoption of this statement has not
had a material impact on our results of operations or financial condition.

On June 1, 2005, the FASB issued SFAS Statement No. 154, "Accounting Changes and
Error Corrections" (SFAS No. 154), which will require entities that voluntarily
make a change in accounting principle to apply that change retrospectively to
prior periods' financial statements, unless this would be impracticable. SFAS
No. 154 supersedes Accounting Principles Board Opinion No. 20, "Accounting
Changes' (APB 20), which previously required that most voluntary changes in
accounting principle be recognized by including in the current period's net
income the cumulative effect of changing to the new accounting principle. SFAS
No. 154 also makes a distinction between "retrospective application" of an
accounting principle and the "restatement" of financial statements to reflect
the correction of an error.

Another significant change in practice under SFAS no. 154 will be that if an
entity changes its method of depreciation, amortization, or depletion for
long-lived, non-financial assets, the change must be accounted for as a change
in accounting estimate. Under APB 20, such a change would have been reported as
a change in accounting principle. SFAS No. 154 applies to accounting changes and
error corrections that are made in fiscal years beginning after December 15,
2005. We do not anticipate any material impact from implementation of this
accounting standard.



                                      F-12
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

<TABLE><CAPTION>
                                                                              DECEMBER 31,
                                                                    ------------------------------
                                                                        2004              2005
                                                                    ------------      ------------
<S>                                                                 <C>               <C>
          Oil and gas properties:
               Subject to amortization                              $ 41,893,564      $ 67,130,448
               Not subject to amortization: Acq. In 2005               1,264,680
                  Acquired in 2004                                       447,786           432,880
                  Acquired in 2003                                          --                --
                  Acquired in 2002                                        76,829            80,156
                  Acquired in 2001                                        34,791            21,100
               Accumulated depreciation, depletion, and
               amortization                                           (6,496,210)       (9,992,867)
                                                                    ------------      ------------
                  Net oil and gas properties                          35,956,760        58,927,397
                                                                    ------------      ------------
          Other property and equipment                                 3,515,422        17,044,734
          Less accumulated depreciation                               (1,308,358)       (1,793,781)
                                                                    ------------      ------------

                 Net other property and equipment                      2,207,064        15,250,953
                                                                    ------------      ------------
                   Property and equipment, net of accumulated
                      Depreciation, depletion, and amortization     $ 38,163,824      $ 74,178,350
                                                                    ============      ============
</TABLE>

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

<TABLE><CAPTION>
                                                                    FOR THE YEAR ENDED
                                                                        DECEMBER 31,
                                                               -----------------------------
                                                                   2004             2005
                                                               ------------     ------------
<S>                                                            <C>              <C>
          Depreciation, depletion, and amortization of oil
             and gas properties                                $  1,707,431     $  3,496,657
          Depreciation of other property and equipment              336,054          485,422
                                                               ------------     ------------

                         Total                                 $  2,043,485     $  3,982,079
                                                               ============     ============
</TABLE>

                                      F-13
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

NOTE C--LONG-TERM DEBT

<TABLE><CAPTION>
                                                                                              DECEMBER 31,
                                                                                       --------------------------
                                                                                          2004           2005
                                                                                       -----------    -----------
<S>                                                                                    <C>            <C>
          Note payable to bank, maturity date of September, 2006,
          bearing a variable interest rate (5.25% as of December 31,
          2005) collateralized by producing oil and gas properties                     $ 1,849,837    $      N/A

          Note payable to bank, maturity date of July 2008 bearing a
          variable interest rate (7.5% as of December 31, 2005)
          collateralized by oil and gas properties                                              N/A         1,000

          Joint venture partner project (financing, non-recourse, no
          interest rate)                                                                 1,912,457      1,755,002
                                                                                       -----------    -----------
                                                                                         3,762,294      1,756,002
          Current portion                                                                  433,933        345,967
                                                                                       -----------    -----------
                Long Term                                                              $ 3,328,361    $ 1,410,035
</TABLE>

      Maturities of long-term debt are as follows:

                                              YEAR           AMOUNT
                                           ---------      ------------
                                                2006      $    345,967
                                                2007           271,855
                                                2008           295,957
                                                2009           215,743
                                                2010           168,784
                                           2011-2015           406,440
                                           2016-2020            51,256
                                                          ------------
                                                          $  1,756,002
                                                          ============

2005 CREDIT FACILITY

On July 29, 2005, the Company entered into a new secured credit facility, which
replaced a prior credit facility. The new credit facility provides for a line of
credit of up to $50,000,000 (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 credit facility 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 credit facility 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. On October 25, 2005,
the bank increased the Borrowing Base to $24,000,000, with quarterly commitment
reduction of $1,500,000. At December 31, 2005, the Company had $1,000 of
borrowings under the credit facility. The credit facility matures in July 2008.

                                      F-14
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

The credit facility contains various affirmative and restrictive covenants.
These covenants, among other things, prohibit additional indebtedness, sales of
assets, mergers and consolidations, dividends and distributions, changes in
management and require the maintenance of various financial ratios.

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 $1.9
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, 2005, the amount
owed under this arrangement was $1,755,002.

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
are depreciated for income tax reporting purposes using accelerated methods.
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.

Deferred income tax assets also are recognized for operating losses that are
available to offset future income taxes.

At December 31, 2005, the Company had the following carryforwards available to
reduce future income taxes:

          Net Operating Losses:
               Federal                                 $ 26,835,000
               State                                      2,466,000
          Statutory depletion                             6,691,000

                                      F-15
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

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.

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

<TABLE><CAPTION>
                                                                  DECEMBER 31,
                                                         ------------------------------
                                                             2004              2005
                                                         ------------      ------------
<S>                                                         <C>               <C>
          Deferred tax assets:
                  Net operating loss carry forwards         9,255,000         9,272,000
                  Statutory depletion carry forwards        1,261,000         2,274,900
                                                         ------------      ------------
                           Total                           10,516,000        11,546,900
                                                         ------------      ------------
          Deferred tax liability:
                  Property, plant and equipment           (10,287,000)      (12,759,000)
                  Valuation allowance                        (229,000)             --
                                                         ------------      ------------
                           Total                          (10,516,000)      (12,759,000)
                                                         ------------      ------------
          Net deferred tax liability                             --          (1,212,100)
                                                         ============      ============
</TABLE>

As of December 31, 2005, a deferred tax liability of $12,759,000 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 $11,546,900 was primarily the result of the net
operating loss and statutory depletion carryforwards.

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
                                            --------       --------
          U.S. statutory tax rate
                                                  34%            34%
          Statutory depletion                    (25)           (12)
          Change in valuation allowance          (24)            (8)
          Other                                   16            -0-
                                            --------       --------
          Effective income tax rate                1%            14%
                                            ========       ========

NOTE E--COMMITMENTS AND CONTINGENCIES

The Company is party to various other legal actions arising in the normal course
of business. Matters that are probable of unfavorable outcome to the Company and
which can be reasonably estimated are accrued. Such accruals are based on
information known about the matters, the Company's estimates of the outcomes of
such matters, and its experience in contesting, litigating, and settling similar
matters. None of the actions are believed by

                                      F-16
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

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, 2005.

Year Ending December 31:

       2006                                         $  118,522
       2007                                             33,217
       2008                                             18,344
       2009                                             18,344
       2010                                             18,344
                                                    ----------
          Total                                     $  206,771
                                                    ==========

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

      2004                                          $  153,613
      2005                                             118,701

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.

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

                                      F-17
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

In January 2004, the Company raised $1 million from the sale of 11% senior
subordinated notes due January 31, 2007 and five-year detachable warrants to
purchase 175,000 shares of common stock for $1.50 per share. The price of the
Company's common shares as of that date was $3.16. The fair market value of the
warrants in the amount of $257,250 were costs of acquiring the debt and
amortized over the life of the debt. These warrants were all exercised for total
proceeds of $262,500 in June 2004.

In addition, in April 2004 the Company closed a private placement of 200,000
shares of common stock for $1,000,000 with a single institutional investor.
Also, in June 21, 2004, the Company closed a private placement of 1,100,000
shares of common stock for $7,535,000 with several institutional investors.
Proceeds of the transactions will be used for general corporate purposes.

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 will be used for general corporate purposes.

The Company's Class A warrants allow holders to purchase common shares of the
Company for $12.00 per share until February 13, 2006 and were issued in
connection with the Company's initial public offering in 2001. During the 4th
quarter of 2004, the Company repurchased 94,600 Class A warrants for $61,930.
Subsequent to the end of the year, the Company received $14,000,000 from the
exercise of warrants.

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 and 2005 were as follows:

                                                        2004         2005
                                                        ----         ----

          Penn Virginia Oil & Gas (Oil)                 ---.           27%
          Teppco Crude (Oil)                             93%           65%
          CrossTex Energy Services, Inc. (Gas)           63%           44%
          Penn Virginia Oil & Gas (Gas)                  21%           48%
          Duke Energy (Gas)                              10%            7%

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, and was
reinstated effective January 1, 2005. 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

                                      F-18
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

contributions dollar for dollar up to 5% of the employees compensation; the
Company contributed $42,875 and $-0- in 2005 and 2004, respectively.

NOTE J--OIL AND GAS OPERATIONS (UNAUDITED)

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 2004 and 2005 are:

<TABLE><CAPTION>
                                                                2004              2005
                                                            ------------      ------------
<S>                                                         <C>               <C>
          Unproved properties                               $    559,407      $  1,789,816
          Producing properties                                41,893,563        67,130,448
                                                            ------------      ------------
                                                              42,452,970        68,920,264
          Less accumulated depreciation, depletion, and
             Amortization                                     (6,496,210)       (9,992,867)
                                                            ------------      ------------

                         Net capitalized costs              $ 35,956,760      $ 58,927,397
                                                            ============      ============
</TABLE>

Unproved properties include leaseholds under exploration. Producing properties
include mineral properties with proved reserves, development wells, and
uncompleted development well costs. Support equipment and facilities include
costs for pipeline facilities, field equipment, and other supporting assets
involved in oil and gas producing activities. 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 and 2005 are as follows:

<TABLE><CAPTION>
                                                        2004             2005
                                                    ------------     ------------
<S>                                                 <C>              <C>
          Property acquisition costs - proved       $       --       $       --
          Property acquisition costs - unproved          851,617        1,230,409
          Development costs                            9,152,257       24,789,281
                                                    ------------     ------------

                                                    $ 10,003,874     $ 26,019,690
                                                    ============     ============
</TABLE>

Developments costs above include non-cash asset retirement costs of $377,017.

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 and 2005 include revenues and
expenses associated directly with oil and gas producing activities.

                                      F-19
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005





<TABLE><CAPTION>


                                                           2004              2005
                                                       ------------      ------------
<S>                                                    <C>               <C>
          Oil and gas sales                            $  7,689,882      $ 19,026,050
          Production costs                               (1,779,830)       (3,311,624)
          Depreciation, depletion and amortization       (1,707,431)       (3,496,657)
          Income tax expense                             (1,047,075)       (1,212,100)
                                                       ------------      ------------
          Results of operations for oil and gas        $  3,155,546      $ 11,005,669
               producing activities
                                                       ============      ============

</TABLE>



















                                      F-20
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

NOTE K--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 and 2005, all of the Company's oil and gas reserves were located in the
United States.

<TABLE><CAPTION>
                                                                  OIL               GAS
                                                                (MBBLS)            (MMCF)
                                                              ------------      ------------
<S>                                                           <C>               <C>
          DECEMBER 31, 2004
             Proved reserves, beginning of period                    1,323            45,029
             Extensions, discoveries, and other additions               51            14,644
             Production                                                (30)           (1,049)
             Revisions of previous estimates                          (107)           (1,736)
                                                              ------------      ------------
             Proved reserves, end of period                          1,237            56,888
                                                              ============      ============
             Proved developed reserves:
                 Beginning of period                                   568            18,277
                                                              ============      ============
                 End of period                                         584            18,980
                                                              ============      ============
          DECEMBER 31, 2005
             Proved reserves, beginning of period                    1,237            56,888
             Extensions, discoveries, and other additions              694            84,026
             Production                                                (48)           (1,930)
             Revisions of previous estimates                            88            11,192
                                                              ------------      ------------
             Proved reserves, end of period                          1,971           150,176
                                                              ============      ============
             Proved developed reserves:
                 Beginning of period                                   584            18,980
                                                              ============      ============
                 End of period                                         770            41,503
                                                              ============      ============
</TABLE>

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

                                      F-21
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005

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.

<TABLE><CAPTION>
                                                             DECEMBER 31,      DECEMBER 31,
                                                                 2004              2005
                                                             ------------      ------------
                                                            (IN THOUSANDS)    (IN THOUSANDS)
<S>                                                          <C>               <C>
          Future cash inflows                                $    375,427      $  1,648,402
          Future production costs                                 (94,338)         (373,614)
          Future development costs                                (66,811)         (190,700)
          Future income tax provisions                            (42,926)         (283,784)
                                                             ------------      ------------

               Net future cash inflows                            165,352           800,304
          Less effect of a 10% discount factor                   (101,120)         (497,908)
                                                             ------------      ------------
               Standardized measure of discounted future
                   net cash flows                            $     64,251      $    302,396
                                                             ============      ============
</TABLE>

Oil and condensate prices were based on an equivalent base price of $61.04 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2005. 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 $57.19 per barrel. Natural gas prices were based on an equivalent base price
of $11.23 per million British thermal unit (mmbtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2005. 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 $10.23 per mmbtu. Future income tax
expenses are computed by applying the appropriate statutory rates to the future
pre-tax net cash flows relating to proved reserves, net of the tax basis of the
properties involved giving effect to permanent differences, tax credits, and
allowances relating to proved oil and gas reserves.

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

                                      F-22
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2004 AND 2005


<TABLE><CAPTION>
                                                                          DECEMBER 31,      DECEMBER 31,
                                                                              2004              2005
                                                                         (IN THOUSANDS)    (IN THOUSANDS)
                                                                          ------------      ------------

<S>                                                                             <C>               <C>
          Standardized measure, beginning of year                               47,975            64,231
          Sales of oil and gas, net of production costs                         (5,910)          (15,714)
          Net changes in prices and production costs                             4,409            49,869
          Extensions and discoveries, net of future development costs           18,949           223,384
          Development costs that reduced future development costs                6,863            23,629
          Revisions of quantity estimates                                       (4,035)           26,174
          Sales of reserves in place                                              --                --
          Accretion of discount                                                 (1,149)           97,164
          Other                                                                 (9,379)          (78,118)
          Net changes in income taxes                                            4,210           (88,223)
                                                                          ------------      ------------

          Standardized measure, end of year                                     64,231           302,396
                                                                          ============      ============
</TABLE>













                                      F-23
<PAGE>

                                  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)

4.1       Warrant Agreement with form of Warrant for the February 12, 2001
          Public Offering (Incorporated by reference to Exhibit 4.1 to the
          Registration Statement on Form SB-2, File No. 333-49328)

4.2       Form of Underwriters' Warrant for the February 12, 2001 Public
          Offering (Incorporated by reference to Exhibit 4.2 to Registration
          Statement on Form SB-2, File No. 333-49328)

4.3       Form of Underwriters' Warrant for the July 17, 2001 Secondary Offering
          (Incorporated by reference to Exhibit 4.2 to the Registration
          Statement on Form SB-2, File No. 333-65436)

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)
<PAGE>

10.4      Loan Agreement dated July 29, 2005 between GMX Resources Inc. and
          Hibernia National Bank. (Incorporated by reference to Exhibit 10.1 to
          Current Report on Form 8-K filed on August 4, 2005)

10.4(a)   Interim Agreement dated November 3, 2005 between GMX Resources Inc.
          and Hibernia National Bank

10.4(b)   Second Amendment to Loan Agreement dated December 20, 2005, between
          GMX Resources Inc. and Hibernia National Bank

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)

10.6      Texas Deed of Trust, Mortgage, Assignment, Security Agreement, Fixture
          Filing and Financing Statement dated as of November 3, 2005 from GMX
          Resources Inc. to Hibernia National Bank (Incorporated by reference to
          Exhibit 10.16 to Form 10-Q for the quarter ended September 30, 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

23.1      Consent of Smith, Carney & Co., p.c.

23.2      Consent of Sproule Associates, Inc.

31.1      Rule 13a-14(a) Certification of Chief Executive Officer

31.2      Rule 13a-14(a) Certification of Chief Financial Officer

32.1      Certification of Chief Executive Officer pursuant to 18 U.S.C. ss.
          1350.

32.2      Certification of Chief Financial Officer pursuant to 18 U.S.C. ss.
          1350.