================================================================================

                    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, 2004


 [_]   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 Identification No.)
     of incorporation)

          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:

NAME OF EACH EXCHANGE ON WHICH REGISTERED

Title of each class
-------------------
COMMON STOCK, $0.001 PAR VALUE                     NASDAQ NATIONAL MARKET SYSTEM
CLASS A WARRANTS                                   NASDAQ NATIONAL MARKET SYSTEM

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. [_]

The issuer's revenue for the year ended December 31, 2004 was $7,833,710.

The aggregate market value of the voting and non-voting common equity (excluding
warrants) held by non-affiliates on March 23, 2005 was $91.9 million. This
amount was computed using closing price of the issuer's common stock on March
22, 2005 on the NASDAQ National Market.

As of March 22, 2005, the issuer had outstanding a total of 8,201,587 shares of
its $0.001 par value Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE - None

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

                               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...................................................3
          Marketing...........................................................4
          Regulation..........................................................5
          Gas Gathering.......................................................7
          Competition.........................................................8
          Facilities..........................................................8
          Employees...........................................................8
          Certain Technical Terms.............................................9

Item 2.   PROPERTIES.........................................................13

          Reserves...........................................................16
          Costs Incurred.....................................................18
          Productive Well Summary............................................19

Item 3.   LEGAL PROCEEDINGS..................................................20


Item 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................20


PART II......................................................................21

Item 5.   MARKET FOR COMMON EQUITY RELATED STOCKHOLDER
          MATTERS, AND SMALL BUSINESS ISSUER PURCHASES OF
          EQUITY SECURITIES..................................................21

          Common Stock and Class A Warrant Information.......................21
          Equity Compensation Plan Information...............................22
          Recent Sales of Unregistered Securities............................22
          Purchases of Equity Securities by the Small Business Issuer........22

Item 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION..........23

          Selected Financial Data............................................23
          Summary Operating and Reserve Data.................................24
          Critical Accounting Policies.......................................25
          Results of Operations for the Year Ended December 31, 2004
             Compared to the Year Ended December 31, 2003....................27
          Results of Operations for the Year Ended December 31, 2003
             Compared to the Year Ended December 31, 2002....................28

                                        i
<PAGE>

          Capital Resources and Liquidity....................................29
          Credit Facility....................................................30
          Other 2004 Financings..............................................31
          Working Capital....................................................31
          Commitments and Capital Expenditures...............................31
          Liquidity and Financing Considerations.............................32
          Price Risk Management..............................................32
          Effect of Accounting Standards.....................................32
          Forward-Looking Statements.........................................33
          Risks Related to GMX...............................................34
          Risks Related to the Oil and Gas Industry..........................36

Item 7.   FINANCIAL STATEMENTS...............................................41


Item 8.   CHANGES  IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
          ACCOUNTING AND FINANCIAL DISCLOSURE................................41


Item 8A.  CONTROLS AND PROCEDURES............................................42


Item 8B.  OTHER INFORMATION..................................................42


PART III.....................................................................43

Item 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
          AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF
          THE EXCHANGE ACT...................................................43

          Significant Employees..............................................44
          Consultant.........................................................44
          Terms..............................................................44
          Section 16(a) Beneficial Ownership Reporting Compliance............45
          Audit Committee Matters............................................45
          Code of Ethics.....................................................45

Item 10.  EXECUTIVE COMPENSATION.............................................46

          Summary Compensation Table.........................................46
          Compensation of Directors..........................................47

Item 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERSHIP
          AND MANAGEMENT.....................................................47


Item 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................48


Item 13.  EXHIBITS...........................................................48


Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES.............................48


SIGNATURES...................................................................50

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

                                       ii
<PAGE>

                                     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, 2004, 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,
2004, we had proved reserves of 64.3 Bcfe and 66 gross (44.3 net) producing
wells. In the North Carthage Field, we also held a large inventory of Cotton
Valley Sand development prospects, including 67 gross (39 net) proved
undeveloped locations and an additional 113 gross (74 net) probable and 275
gross (150 net) possible drilling locations depending on the area of well
spacing. Our strategy is to significantly grow production and natural gas
reserves and build shareholder value.

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.

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 expire 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.

                                        1
<PAGE>

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.

2003 YEAR END AND 2004 DEVELOPMENTS

            During the fourth quarter of 2003, we were able to successfully find
an industry partner to assist us in developing our East Texas properties.

            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," which includes approximately 7,817 gross (2,173 net) acres comprising a
portion of our proved undeveloped acreage. We have a 20% carried interest in the
first seven wells drilled in Phase I and a right to participate for up to 30% of
additional Phase I wells. Phase II, which includes approximately 6,931 gross
(3,325 net) acres of our acreage, must commence no later than July 1, 2005. In
Phase II, we have a 20% carried interest in the first two wells and will have a
right to participate for up to 50% of additional drilling in Phase II. In
December 2003, we received approximately $950,000 in acreage and drilling
location cost reimbursement that was applied to reduce current liabilities. For
additional information concerning the PVOG agreement, see "Item 2 - Properties."

            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

                                        2
<PAGE>

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.

            As a result of our improved liquidity in 2004, our bank extended the
maturity date of our credit facility to September 1, 2006 and increased the
borrowing base to $10,000,000 (as of October 25, 2004) with monthly commitment
reductions of $120,000. See "Management's Discussion and Analysis on Plan of
Operation."

            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.

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. We have a
substantial inventory of drilling and recompletion projects with an estimated 42
Bcfe of proved undeveloped reserves as of December 31, 2004. These projects
include 31 recompletion projects and 67 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

                                        3
<PAGE>

on our December 31, 2004 reserve report, the pre-tax present value of the proved
reserves is $83 million with anticipated future development costs of $67
million.

            SIGNIFICANT INVENTORY OF UNPROVED PROSPECTS. We have approximately
388 gross/224 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 13,954 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 2004 was 85% gas and 15%
oil. Proved reserves as of December 31, 2004 are 88% gas and 12% oil. We intend
to emphasize acquisition 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. We consider that our relationship with PVOG is
good.

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

MARKETING

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

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

            Substantially all of our gas from our East Texas company-operated
wells is initially sold to our wholly owned subsidiary, Endeavor Pipeline Inc.
("Endeavor"), which in turn sells gas to unrelated third parties. All of our gas
is currently sold under contracts providing for market sensitive terms which are
terminable with 30-60 day notice by either party without penalty. This means
that we enjoy both the high prices in increasing price markets and suffer the
price declines when gas prices decline. In addition, PVOG markets 100% of the
gas produced from wells

                                        4
<PAGE>

operated by PVOG in Phase I 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 2004, our largest purchasers were Crosstex Pipeline Company, PVOG
and TEPPCO Crude, which accounted for 53%, 18% and 15% of total oil and natural
gas sales. We do not believe that the loss of any of our purchasers would have a
material adverse affect on our operations as there are other purchasers active
in the market.

REGULATION

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

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

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

                                        5
<PAGE>

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

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

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

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

                                        6
<PAGE>

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

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

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

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

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

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

GAS GATHERING

            We have acquired, constructed and own, through a wholly owned
subsidiary, Endeavor Pipeline, Inc., gas gathering lines and compression
equipment for gathering and delivering of natural gas from our East Texas
properties that we operate. As of December 31, 2004, this gathering system
consisted of approximately 35 miles of gathering lines and one Ajax DPC-360,

                                        7
<PAGE>

360 horsepower, two-stage compressor that collect and compress gas from
approximately 95% of our gas production from company-operated wells in both 2003
and 2004. 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 Phase I of our joint development. 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, 2004, we leased approximately 6,749 square feet
in Oklahoma City, Oklahoma for our corporate headquarters. The annual rental
cost is approximately $89,235.

EMPLOYEES

            As of December 31, 2004, we had 11 full-time employees of which
three are management and the balance are clerical or technical employees. This
compares to eight full-time employees at December 31, 2003. We also use seven
independent contractors to assist in field operations. We believe our relations
with our employees are satisfactory. Our employees are not covered by a
collective bargaining agreement.

                                        8
<PAGE>

CERTAIN TECHNICAL TERMS

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

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

            BCF. Billion cubic feet.

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

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

            BBTU. Billion Btus.

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

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

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

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

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

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

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

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

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

                                        9
<PAGE>

            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.

            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

                                       10
<PAGE>

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 do estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery techniques is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.

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

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

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

                                       11
<PAGE>

            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.


















                                       12
<PAGE>

ITEM 2.     PROPERTIES

GENERAL

            As of December 31, 2004, 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, 2004.
<TABLE><CAPTION>
                                                             EAST TEXAS AND   SOUTHEAST
                                                               LOUISIANA      NEW MEXICO    TOTAL
                                                               ---------      ----------    -----
<S>                                                              <C>             <C>        <C>
            PROPERTY STATISTICS:
            Proved reserves (MMcfe)                              63,038          1,271      64,309
            Percent of total proved reserves                       99%             1%        100%
            Gross producing wells                                   59              7          66
            Net producing wells                                   38.7            5.6        44.3
            Gross acreage                                        23,329          1,760      25,059
            Net acreage                                          12,659          1,478      14,135
            Proved developed reserves (MMcfe)                    22,000            481      22,481
            Proved undeveloped reserves (MMcfe)                  41,038            790      41,828
            Estimated total future development costs ($000s)     66,011            800      66,811
            Estimated 2005 development costs ($000s)             15,000            --       15,000
            Proved undeveloped locations                             66              1          67

            YEAR ENDED DECEMBER 31, 2004 RESULTS:
            Production (net MMcfe)                                1,178             53       1,231
            Average net daily production (Mcfe)                   3,227            145       3,372
</TABLE>

            Additional information related to our oil and gas activities is
included in Notes I and J 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 22,729 gross (12,288
net) acres with rights covering the Travis Peak, Pettit, Glen Rose and Cotton
Valley formations. Our East Texas properties have 62.6 Bcfe of proved reserves
or 97% of our total proved reserves at December 31, 2004, of which 41.0 Bcfe is
classified as proved undeveloped.

                                       13
<PAGE>

            We have interests in 54 gross (36.0 net) producing wells in East
Texas, of which we operate 36. Average daily production net to our interest for
2004 was 2,834 Mcf of gas and 62 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 36 gross (30.7 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. 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," which includes approximately 7,817 gross (2,173 net) acres comprising a
portion of our proved undeveloped acreage. GMX has a 20% carried interest in the
first wells drilled in Phase I and a right to participate for 30% of additional
Phase I wells. PVOG has drilled and completed 15 wells in 2004 on the Phase I
acreage. Phase II, which includes approximately 6,931 gross (3,325 net) acres of
our acreage, must commence no later than July 1, 2005. In Phase II, we have a
20% carried interest in the first two wells and a right to participate for up to
50% of additional drilling in Phase II. At inception, we received approximately
$950,000 in acreage and drilling location cost reimbursement which was applied
to reduce current liabilities. During 2004, we received an additional $125,541
in drilling location cost reimbursement.

            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 Phase I 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 Phase II AMI consists of 22,400 acres and a 50% PVOG/50% GMX
sharing ratio. The Phase III 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 Phase III and PVOG is restricted from
acquiring acreage in Phase III until one year after termination of the
participation agreement, unless GMX no longer

                                       14
<PAGE>

owns acreage in Phase III. In 2004, we jointly acquired 2,665 gross acres in
Phase I and 670 acres in Phase II.

            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. 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. Either party may terminate the multiple rig provisions
on 60 days notice subject to the terms of any drilling contract for the second
rig.

            During 2004, GMX participated in 17 gross (4.6 net) new wells
drilled by PVOG in Phase I and recompleted eight wells in Phase III. Fifteen of
the new wells were drilled and completed and had sales in 2004. At year end, the
remaining two were in the process of drilling or completion. The success rate
was 100% on wells drilled and completed in 2004. 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. There is a
potential for up to 455 gross (263 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, 2004, Sproule Associates, Inc., our independent
reserve engineering firm, assigned a total of 13.8 Bcfe of proved reserves to
the completed East Texas wells, 7.8 Bcfe to our proved developed non-producing
wells, and 30.5 Bcfe of proved undeveloped reserves to our 66 proved undeveloped
locations in East Texas.

            As discussed above, in March 2005, we and PVOG reached an agreement
to use a second rig in Phases I and II. When a second rig is located and put in
service, drilling in East Texas will be accelerated. We are also seeking an
additional rig for our own use in Phase III drilling. Depending on rig
availability and funding, we expect PVOG to drill 13-25 new Cotton Valley wells
in Phase I and two Cotton Valley wells in Phase II and we expect to drill 2-16
Cotton Valley wells in Phase III. We also plan to recomplete 4-6 wells in Phase
III. 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.

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 (2.6 net) producing wells, three of which
we operate. Production is predominately oil. Louisiana

                                       15
<PAGE>

proved reserves are 0.4 Bcfe and represent approximately 1% of proved reserves
as of December 31, 2004. Average daily production net to our interest for 2003
was 2 Bbls of oil and 8 Mcf of gas. We are in the process of evaluation of
additional behind pipe and undeveloped reserves in the region. The wells are
producing around a piercement saltdome which has produced numerous structural
traps for oil.

SOUTHEAST NEW MEXICO

            Our Southeast New Mexico properties are located in Lea and Roosevelt
counties and consist of approximately 1,760 gross (1,478 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 Andreas--at
depths ranging from 9,500 to 10,000 feet. Proved reserves in Southeast New
Mexico are 1.3 Bcfe and represent 1% of our total proved reserves as of December
31, 2004. Average daily production net to our interests for 2004 from our 7
gross (5.6 net) producing wells in this area was 31 Mcf of gas and 19 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. We plan
to participate with Yates in a 12,000-foot Morrow sand test expected to commence
in April 2005. We will have a 23% working interest in this well and also have
retained a 5.75% overriding royalty interest.

RESERVES

            As of December 31, 2004, Sproule Associates Inc. estimates our
proved reserves are 64 Bcfe. An estimated 22 Bcfe is expected to be produced
from existing wells and another 42 Bcfe or 65% of the proved reserves, is
classified as proved undeveloped. All of our proved undeveloped reserves are on
locations that are adjacent to wells productive in the same formations. As of
December 31, 2004, we had interests in 66 gross producing wells, 39 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.



                                       16
<PAGE>
<TABLE><CAPTION>
                                                       YEARS ENDED DECEMBER 31,
                                                     2002        2003        2004
                                                   --------    --------    --------
<S>                                                 <C>         <C>         <C>
PROVED DEVELOPED:
Gas (MMcf)                                           16,501      18,277      18,980
Oil (MBbls)                                             604         568         584
                                Total (MMcfe)        20,125      21,685      22,484
PROVED UNDEVELOPED:
Gas (MMcf)                                           40,181      26,752      37,908
Oil (MBbls)                                           1,060         755         653
                                Total (MMcfe)        46,541      31,282      41,826
TOTAL PROVED:
Gas (MMcf)                                           56,683      45,029      56,888
Oil (MBbls)                                           1,663       1,323       1,237
                                Total (MMcfe)        66,663      52,967      64,309

ESTIMATED FUTURE NET REVENUES (1)($000S)           $186,336    $178,348    $214,278

PRESENT VALUE(1)($000S)                            $ 80,614    $ 71,192    $ 83,237

STANDARDIZED MEASURE (1) ($000S)                   $ 54,312    $ 47,975    $ 64,231
-------------------------
</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 J - 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.

            There was a significant decrease in proved reserves from December
31, 2002 to December 31, 2003. We produced 1.1 Bcfe which was not replaced due
to the absence of drilling in 2003. In addition, our proved reserve estimates at
December 31, 2003 were revised downward by 13.7 Bcfe compared to December 31,
2002 primarily as a result of a participation agreement with PVOG in December,
2003, under which PVOG acquired certain rights in our East Texas properties. The
increase in proved reserves in 2004 is primarily attributable to discoveries
resulting from our East Texas drilling results and increases in commodity
prices.

            Approximately 65% 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 $67 million as of December 31, 2004, of which $15 million is scheduled
to be expended in 2005. These estimated costs may not be accurate, development
may not occur as scheduled and results may not be as estimated.

                                       17
<PAGE>

            Estimates of the quantity and value of our proved undeveloped
reserves are dependent upon the amount of interest that we expect to own in
these reserves. In connection with the PVOG participation agreement executed in
December of 2003, PVOG's rights in Phase II of the agreement are contingent upon
PVOG's successful completion of Phase I and the drilling of two carried interest
wells in Phase II before July 1, 2005. Our year end reserve estimates assume
that PVOG will earn all of its rights in the Phase II acreage. Our reserve
estimates would be increased if PVOG does not earn rights in Phase II.

            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, 2004 were $43.45 per
barrel for oil and $6.149 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 $511,800 and
$2,374,000, respectively, as of December 31, 2004.

            Sproule Associates, Inc., our independent reserve engineers,
prepared the estimates of proved reserves as of December 31, 2002, 2003, and
2004.

            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.


                                               YEAR ENDED DECEMBER 31,
                                      -----------------------------------------
                                          2002           2003           2004
                                      -----------    -----------    -----------
PROPERTY ACQUISITION COSTS:

                        Proved        $   120,157    $    57,565    $       --
                        Unproved           84,672          5,212        851,617
DEVELOPMENT COSTS                       2,812,876        173,840      7,716,073
                                      -----------    -----------    -----------
                        Total         $ 3,017,705    $   236,617    $ 8,567,690
                                      ===========    ===========    ===========

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 acquisition and drilling activities as necessarily indicative of future

                                       18
<PAGE>

performance, nor should you assume that there is necessarily any correlation
between the number of productive wells acquired or drilled and the oil and gas
reserves generated by those wells.


                                          YEAR ENDED DECEMBER 31,
                          -----------------------------------------------------
                               2002                2003                2004
DEVELOPMENT WELLS:        Gross     Net       Gross     Net       Gross     Net
Gas                        --       --         --       --         15        4
Oil                        --       --         --       --         --       --
Dry                        --       --         --       --         --       --
                          ----     ----       ----     ----       ----     ----
Total                      --       --         --       --         15        4
                          ====     ====       ====     ====       ====     ====

            We also recompleted 8 gross and net in 2004. We did not recomplete
any wells in 2003 and 2002.

ACREAGE

            The following table shows our developed and undeveloped oil and gas
lease and mineral acreage as of December 31, 2004. 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          15,804        9,445        7,526        3,212
Southeast New Mexico               1,760        1,478          ---          ---
                               ----------   ----------   ----------   ----------
               Total              17,564       10,923        7,526        3,212
                               ==========   ==========   ==========   ==========

            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, 2004 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.

                                       19
<PAGE>

                                        PRODUCTIVE WELLS
                                        ----------------
            TYPE OF WELL                GROSS       NET
            ------------                -----     ------
            Gas                           46       29.8
            Oil                           20       14.5
                                        -----     ------
                               Total      66       44.3
                                        =====     ======

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 2004.

























                                       20
<PAGE>

                                     PART II

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

COMMON STOCK AND CLASS A WARRANT INFORMATION

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

                                                              HIGH       LOW
                                                              ----       ---
            YEAR ENDED DECEMBER 31, 2003
                   FIRST QUARTER
                         Common Stock                        $ 1.96     $ 1.06
                         Class A Warrants                      0.50       0.05
                   SECOND QUARTER
                         Common Stock                          2.14       0.63
                         Class A Warrants                      0.49       0.04
                   THIRD QUARTER
                         Common Stock                          2.23       1.33
                         Class A Warrants                      0.19       0.09
                   FOURTH QUARTER
                         Common Stock                          4.50       1.30
                         Class A Warrants                      0.72       0.09
            YEAR ENDED DECEMBER 31, 2004
                   FIRST QUARTER
                         Common Stock                          6.08       2.45
                         Class A Warrants                      0.98       0.27
                   SECOND QUARTER
                         Common Stock                          8.30       5.10
                         Class A Warrants                      1.48       0.63
                   THIRD QUARTER
                         Common Stock                          7.80       5.31
                         Class A Warrants                      1.00       0.40
                   FOURTH QUARTER
                         Common Stock                          7.75       5.86
                         Class A Warrants                      0.93       0.50

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

            As of March 1, 2005, there were 46 record owners of our Common Stock
and approximately 1,264 beneficial owners.

            Each Class A Warrant entitles the holder to purchase one share of
common stock for $12.00 per share until the warrants expire on February 12,
2006.

            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

                                       21
<PAGE>

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, 2004
relating to equity compensation plans.
<TABLE><CAPTION>
                                                                                   REMAINING SHARES
                                 NUMBER OF SHARES TO BE    WEIGHTED-AVERAGE      AVAILABLE FOR FUTURE
                                ISSUED UPON EXERCISE OF    EXERCISE PRICE OF    ISSUANCE UNDER EQUITY
      PLAN CATEGORY               OUTSTANDING OPTIONS     OUTSTANDING OPTIONS     COMPENSATION PLANS
-----------------------------   -----------------------   -------------------   ---------------------
<S>                                     <C>                      <C>                   <C>
Equity Compensation Plans
Approved by Shareholders                254,000                  $4.29                 296,000

Equity Compensation Plans Not
Approved by Shareholders                 60,000                  $1.00                    --
</TABLE>

            The 60,000 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 2004.

PURCHASES OF EQUITY SECURITIES BY THE SMALL BUSINESS ISSUER

            The following table provides information about our purchases of
Class A Warrants in the open market during the fourth quarter of 2004.
<TABLE><CAPTION>
                                                        Total Number          Maximum Number
                                                        of Warrants           of Shares that
                     Total Number   Average Price   Purchased as Part of        May Yet Be
                     of Warrants      Paid per       Publicly Announced       Purchased Under
     Period           Purchased        Warrant       Plans or Programs     the Plans or Programs
------------------   ------------   -------------   --------------------   ---------------------
<S>                       <C>         <C>                    <C>                   <C>
October 2004......         500         $  .71                 500                   (1)
November..........       3,300            .60               3,300                   (1)
December 2004.....      90,800            .65              90,800                   (1)
                     ------------   -------------   --------------------   ---------------------
Total 2004........      94,600         $  .65              94,600                   (1)
                     ============   =============   ====================   =====================
</TABLE>
--------------------
(1) We announced on October 5, 2004 a warrant repurchase program authorizing
management to spend up to $250,000 to acquire our Class A Warrants in the open
market at prices deemed attractive by management from time to time. Through
December 31, 2004, $61,930 had been spent on such repurchases. There has been no
time limit set for completion of the repurchase program. The maximum number of
warrants that may be purchased is not determinable as it is dependent on the
price of the warrants.

                                       22
<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,
                                                              ------------------------------------------------
                                                                  2002              2003              2004
                                                              ------------      ------------      ------------
<S>                                                           <C>               <C>               <C>
STATEMENT OF OPERATIONS DATA:
Oil and gas sales                                             $  5,970,792      $  5,367,370      $  7,689,882
Interest and other income                                           17,550            21,424           143,828
                                                              ------------      ------------      ------------
            Total revenues                                       5,988,342         5,388,794         7,833,710
                                                              ------------      ------------      ------------
Lease operations                                                 1,324,481           850,034         1,261,109
Production and severance taxes                                     382,826           384,069           518,712
General and administrative                                       2,577,388         1,578,865         1,985,913
Depreciation, depletion and amortization                         1,901,976         1,549,678         2,043,485
Interest                                                           510,472           439,313           558,504
                                                              ------------      ------------      ------------
            Total expenses                                    $  6,697,142      $  4,801,959      $  6,367,731
                                                              ------------      ------------      ------------
Income (loss) before income taxes                                 (708,800)          586,835         1,465,979
Income tax expense (benefit)                                      (263,000)             --              24,206
                                                              ------------      ------------      ------------
Net income before cumulative effect of a
change in accounting principle                                $   (445,800)     $    586,835      $  1,441,773

Cumulative effect of a change in accounting principle                 --             (51,834)             --
                                                              ------------      ------------      ------------
Net income (loss) applicable to common shares                 $   (445,800)     $    535,001      $  1,441,773
                                                              ============      ============      ============

Net income (loss) per share - before cumulative effect        $       (.07)     $        .09      $        .19
Cumulative effect                                                     --                (.01)             --
                                                              ------------      ------------      ------------
Net income (loss) per share - basic and diluted               $       (.07)     $        .08      $        .19
                                                              ============      ============      ============

Weighted average common shares - basic                           6,550,000         6,560,000         7,396,880
Weighted average common shares - diluted                         6,550,000         6,560,000         7,491,778

STATEMENT OF CASH FLOWS DATA:
Cash provided by (used in) operating activities               $ (2,547,639)     $  1,014,290      $  3,708,478
Cash provided by (used in) investing activities                  1,267,831           464,315        (8,902,267)
Cash provided by (used in) financing activities                  1,820,000        (1,385,000)        5,418,813

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net                                   $ 29,359,309      $ 27,660,317      $ 35,956,760
Total assets                                                    33,319,432        31,501,206        40,991,463
Long-term debt, including current portion                        8,100,000         6,690,000         3,762,294
Shareholders' equity                                            21,607,463        22,618,565        32,406,856
</TABLE>

                                       23
<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.


                                                  YEARS ENDED DECEMBER 31,
                                           -------------------------------------
                                              2002          2003          2004
                                           ---------     ---------     ---------
PRODUCTION:

Oil(MBbls)                                        70            35            30
Natural gas(MMcf)                              1,639           917         1,049
Gas equivalent(MMcfe)                          2,059         1,124         1,231

AVERAGE SALES PRICE:

Oil(per Bbl)                               $   23.48     $   30.41     $   40.83
Natural gas(per Mcf)                           3.03(1)       4.73(1)       6.15

AVERAGE SALES PRICE(PER MCFE)              $    3.22     $    4.79     $    6.25

OPERATING AND OVERHEAD COSTS(PER MCFE):

Lease operating expenses                   $     .64     $     .74     $    1.03
Production and severance taxes                   .19           .34           .42
General and administrative                      1.25          1.40          1.61
                                           ---------     ---------     ---------
            Total                          $    2.08     $    2.48     $    3.06
                                           ---------     ---------     ---------

OPERATING MARGIN(PER MCFE)                 $    1.14     $    2.31     $    3.19

OTHER(PER MCFE):

Depreciation, depletion and amortization
 - oil and gas production                  $     .92     $    1.08     $    1.28

ESTIMATED NET PROVED RESERVES(AS OF
PERIOD-END):

Natural gas(Bcf)                                56.7          45.0          56.9
Oil(MMbls)                                       1.7           1.3           1.2
Total(Bcfe)                                     66.7          53.0          64.3
Estimated Future Net Revenues($MM)(2)(3)   $   486.3     $   178.3     $   214.3
Present Value($MM)(2)(3)                   $    80.6     $    71.2     $    83.2
Standardized measure of discounted
 future net cash flows($MM)(4)             $    54.3     $    48.0     $    64.2

--------------
(1)  Net of results of hedging activities which reduced the average gas price in
     2002 $.40 per Mcf and $.48 per Mcf in 2003.

(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."

(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 J - Supplemental Information on Oil and Gas
     Operations."

                                       24
<PAGE>

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. For example, in 2002 our reserves were revised downward by
13.5 Bcfe. There can be no assurance that significant revisions will not be
necessary in the future. If future significant revisions are necessary that
reduce previously estimated reserve quantities, it could result in a full cost
property writedown. In addition to the impact of the estimates of proved
reserves on the

                                       25
<PAGE>

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. Increases in the ARO
liability due to passage of time impact net income as accretion expense. The
related capitalized cost, including revisions thereto, is charged to expense
through DD&A.

                                       26
<PAGE>

At December 31, 2004, the Company's balance sheet included an estimated
liability for ARO of $1,764,631.

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, 2004,
we estimated that our deferred tax liabilities and deferred tax assets were
equal in amount after the effects of our establishing a $229,000 valuation
allowance as it is unlikely that we will be able to use our net operating loss
carryforwards prior to their expiration.

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 of 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, a 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 increase resulted
primarily from the increase in oil and gas sales prices and an increase in
production.

                                       27
<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 of $407,048 was the result of an increase in salaries and
payroll expenses 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.

RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2003 COMPARED TO THE YEAR
ENDED DECEMBER 31, 2002

            OIL AND GAS SALES. Oil and gas sales in the year ended December 31,
2003 decreased 10% to $5,367,370 compared to the year ended December 31, 2002
due to decreased production, which was not fully offset by higher prices. The
average price per barrel of oil and mcf of gas received in 2003 was $30.41 and
$4.73, respectively, compared to $23.45 and $3.03 in 2002. 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 2003 decreased compared to 2002. Gas production decreased to 916
MMcf in 2003 compared to 1,639 MMcf for 2002, a decrease of 44%. Decreased
production and revenues in 2003 resulted from higher decline rates, production
down time and a lack of funds to workover or drill wells.

            LEASE OPERATIONS. Lease operations expense decreased $496,968 in
2003 to $827,413, a 38% decrease compared to 2002. Decreased expenses resulted
from the sale of Kansas properties and a lack of funds to make material
workovers to our wells. Lease operations expense on an equivalent unit of
production basis was $.74 per Mcfe in 2003 compared to $.64 per Mcfe for 2002,
primarily from the decreased production coupled with fixed costs.

            PRODUCTION AND SEVERANCE TAXES. Production and severance taxes
increased 3% to $384,069 in 2003 compared to $382,826 in 2002. 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 increase resulted
primarily from the increase in oil and gas sales prices mitigated by the
decrease in production.

            DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion
and amortization expense decreased $329,777 to $1,572,199 in 2003, down 17% from
2002. This decrease is due primarily to a decrease in production for 2003. The
oil and gas depreciation, depletion and

                                       28
<PAGE>

amortization rate per equivalent unit of production was $1.08 per Mcfe in 2003
compared to $0.92 per Mcfe in 2002.

            INTEREST. Interest expense for the year 2003 was $439,313 compared
to $510,472 for the year of 2002. This decrease is primarily attributable to
lower debt balances outstanding during 2003.

            GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative
expense for 2003 was $1,578,865 compared to $2,577,358 for 2002, a decrease of
39%. This decrease of $998,523 was the result of a decrease in salaries and
payroll expenses of $741,000 and a decrease in legal and professional fees
primarily in connection with the Nabors Drilling lawsuit. The salary decrease
was a result of a decrease in administrative personnel. General and
administrative expense per equivalent unit of production was $1.40 per Mcfe for
the 2003 period compared to $1.25 per Mcfe for the comparable period in 2002.

            INCOME TAXES. Income tax for year of 2003 was $0 as compared to a
benefit of $263,000 in 2002. During 2002, we established a valuation allowance
for our deferred tax asset. During 2003, we reversed the valuation allowance to
the extent of our 2003 income.

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, 2004 COMPARED TO YEAR ENDED
DECEMBER 31, 2003. In 2004 we had a positive cash flow from operating activities
of $3,708,478 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
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.

            CASH FLOW--YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED
DECEMBER 31, 2002. In 2003 we had a positive cash flow from operating activities
of $1,014,290 as a result of increased oil and gas prices during 2003. Our cash
flow from operating activities in 2002 was a deficit of $2,547,639 primarily due
to a reduction in net income and decreases in accounts payable of $4,454,155. We
received a net $464,315 in cash from investing activities in 2003 compared to
2002 amounts of $1,267,851. The cash inflow in 2003 was primarily from the
year-end agreement with PVOG. The cash inflow in 2002 from investing activities
primarily resulted from sale of our Kansas properties for $4,245,163 which more
than offset additions to oil and gas properties of $3,014,288.

                                       29
<PAGE>

CREDIT FACILITY

            On October 31, 2000, we entered into a secured credit facility
provided by IBC Bank (formerly Local Oklahoma Bank, N.A.). The credit facility
provided for a line of credit of up to $15 million (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 to us at any one time under this credit facility
is the lesser of the Borrowing Base or the amount of the Commitment. The amount
of this Borrowing Base has been adjusted from time to time, most recently as of
October 25, 2004 to $10,000,000 with a monthly required reduction of $120,000.

            The credit facility has been amended on several occasions to waive
non-payment default or to extend the maturity. In June 2004, a new maturity date
of September 1, 2006 was established. During 2004, we were able to reduce the
amount outstanding under this facility from proceeds of stock sales and cash
flow from operations.

            As of December 31, 2004, we had $1,849,837 outstanding under the
facility. As of March 1, 2005, we had $3,150,000 outstanding and $6,250,000
available for borrowing.

            Borrowings under the credit facility bear interest at the prime rate
to prime plus 1% depending on the level of actual borrowings in relation to the
Borrowing Base. The credit facility requires payment of an annual facility fee
equal to 1 /2 % on the unused amount of the Borrowing Base. We are 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
our oil and gas properties. The credit facility contains various affirmative and
restrictive covenants. The material covenants, which must be satisfied unless
the lender otherwise agrees:

     o    Require us to maintain an adjusted current ratio as defined in the
          credit facility of 1 to 1.

     o    Require us to maintain a quarterly debt service coverage ratio of at
          least 1.1 to 1.0. The debt service coverage ratio is defined in the
          credit facility generally as net income plus depreciation, depletion
          and amortization plus interest expense divided by the quarterly
          principal reduction requirements plus interest and current maturities
          of other long-term debt.

     o    Require us to maintain a ratio of indebtedness to tangible net worth
          of not more than 1.5 to 1.

     o    Prohibit any liens or any other debt in excess of $100,000.

     o    Prohibit sales of assets of more than $100,000.

     o    Prohibit payment of dividends or repurchases of stock.

     o    Prohibit mergers or consolidations with other entities without being
          the controlling entity.

     o    Prohibit material changes in management.

                                       30
<PAGE>

            During 2005, we expect to seek proposals from other banks to
determine whether we may be able to obtain more favorable terms for our bank
credit facility as a result of our improved financial condition and results of
operation.


OTHER 2004 FINANCINGS

            SUBORDINATED NOTES. In January 2004, we 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 our common shares as of that date was $4.01. For accounting
purposes, the fair value of the in-the-money warrants increased the effective
interest rate of the notes. Those notes were repaid in June 2004 with bank debt.
Also, the warrants were all exercised during 2004 resulting in proceeds of
$262,500.

            COMMON STOCK PRIVATE PLACEMENTS. In April 2004, we closed a private
placement of 200,000 shares of common stock for $1,000,000 with a single
institutional investor. Also, in June 2004, we completed another private
placement and sold 1,100,000 shares of common stock for $7,535,000. Proceeds of
these have been used for general corporate purposes, primarily drilling in our
East Texas properties.

            PVOG FINANCING. As described in Part I, Item 2. Properties - East
Texas, we entered into an arrangement with PVOG to purchase dollar denominated
production payments from us on wells drilled with a second rig during a portion
of 2004. Under this agreement, PVOG provided to us $1.9 million in funding for
our share of costs of four wells drilled with the second rig, which is repayable
solely from 75% of our share of production revenues from these wells without
interest. As of December 31, 2004, the Present Value of our interest in the
wells funded in this manner was $2.8 million.


WORKING CAPITAL

            At December 31, 2004, we had a working capital deficit of $392,274.
Including availability under our credit facility, our working capital as of
December 31, 2004 would have been $7,517,889. Total bank and PVOG financing debt
outstanding at December 31, 2004 was $3.76 million, representing 10.4% of our
total capitalization.

COMMITMENTS AND CAPITAL EXPENDITURES

            The following table reflects the Company's contractual obligations
as of December 31, 2004.

                                        Payments Due by Period
                    -----------------------------------------------------------
  Contractual                     Less than       1-3         3-5     More than
  Obligations          Total       1 year        years       years     5 years
------------------  -----------  -----------  -----------  ---------  ---------
Long-term debt....  $ 1,849,837  $       --   $ 1,849,837  $    --    $    --
Operating leases..      232,755      100,357      132,398       --         --
PVOG Financing....    1,912,457      433,933    1,478,523       --         --
                    -----------  -----------  -----------  ---------  ---------
Total.............  $ 3,995,049  $   534,290  $ 3,460,758  $    --    $    --
                    ===========  ===========  ===========  =========  =========

                                       31
<PAGE>

            Other than obligations under our credit facility and the PVOG
financing, 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.

LIQUIDITY AND FINANCING CONSIDERATIONS

            As a result of the participation agreement with PVOG, our 2004
financing and drilling activities and higher commodity prices, our financial
condition and liquidity substantially improved. We expect production from our
wells drilled and completed in 2004 and 2005 to provide cash flow to support
additional drilling. Our 2005 cash flow should be significantly greater than
2004 assuming commodity prices do not decrease significantly. In addition, we
will have availability under our credit facility ($6,250,000 as of March 15,
2005 based on the last Borrowing Base determination of $10 million effective as
of October 25, 2004) and expect that increases in the Borrowing Base may occur
during the year as additional production is established. As a result, we believe
we could fund from these sources from $15 to $20 million in capital
expenditures, depending on gas prices and drilling results. If additional rigs
become available in East Texas during the year, we would need additional
financing from drilling funds or additional equity or debt placements to fund
additional capital expenditures.

            Our Class A Warrants are exercisable at $12 per share and if the
1,107,215 warrants outstanding as of March 15, 2005 were exercised, we would
receive $13 million from sales of 1,107,215 shares of common stock. These
warrants expire in February 2006 and we expect them to be exercised prior to
that date if they are in the money. Accordingly, we may defer additional equity
placements if, based on our stock price, it appears these warrants will be
exercised.

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. 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 June 2001, FASB Statement No. 143, Accounting for Asset
Retirement Obligations, was issued. Statement 143 required us to record the fair
value of an asset retirement obligation as a liability in the period in which we
incur a legal obligation associated with the retirement of tangible long lived
assets that result from the acquisition, construction, development, and/or
normal use of the assets. We also recorded a corresponding asset that is
depreciated over the life of the asset. Subsequent to the initial measurement of
the asset retirement obligation, the obligation will be adjusted at the end of
each period to reflect the passage of time and changes in the estimated future
cash flows underlying the obligation. We adopted Statement 143 on January

                                       32
<PAGE>

1, 2003 and recognized, as the fair value of the asset retirement obligations
$281,516. Due to the adoption of Statement 143, we recognized a charge for this
cumulative effect of change in accounting principle of $51,834.

            In September 2004, the staff of the SEC issued Staff Accounting
Bulletin No. 106 (SAB 106) to express the staff's views regarding application of
FAS 143, "Accounting for Asset Retirement Obligations," by oil and gas producing
companies following the full cost accounting method. SAB 106 addressed the
computation of the full cost ceiling test to avoid double-counting asset
retirement costs, the disclosures a full cost accounting company is expected to
make regarding the impacts of FAS 143, and the amortization of estimated
dismantlement and abandonment costs that are expected to result from future
development activities. We adopted the accounting and disclosures described in
SAB 106 as of the third quarter of 2004 and it did not have a material impact on
our financial position or our results of operations.

            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
interim and annual periods that begin after June 15, 2005 and will be adopted by
the Company in the third quarter of 2005. See Note 1 of our financial statements
for a disclosure of the effect on net income and earnings per share for the
years 2003 and 2004 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. We do not expect this statement to have a
material impact on our results of operations or financial condition.

            In November 2004, the FASB issued Statement on Financial Accounting
Standards No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4,"
which clarifies the types of costs that should be expensed rather than
capitalized as inventory. The provisions of FAS 151 are effective for years
beginning after June 15, 2005. We do not expect this statement to have a
material impact on our results of operations or financial condition.

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

                                       34
<PAGE>

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 20.3% and 11.9% 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 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., his father
and his brother. Because of the family relationship among members of management,
certain employer/employee relationships, including performance evaluations and
compensation reviews may not be

                                       34
<PAGE>

conducted on a fully arms-length basis as would be the case if the family
relationships did not exist. Our board of directors include members unrelated to
the Kenworthy family and we expect that significant compensation and other
relationship issues between GMX and its management will be reviewed and approved
by an appropriate committee of outside directors. However, as the owners of a
significant percentage of our common stock, the Kenworthys have significant
influence over the current directors.

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

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

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

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

OUR CREDIT HISTORY MAY IMPAIR OUR ABILITY TO OBTAIN NECESSARY SERVICES.

            As a result of our problems in 2002 and 2003 in satisfying past due
accounts payable, we may have difficulty in securing trade credit with
contractors and others we need to engage to perform services on existing wells
or in connection with new drilling even if we have capital available for such
purpose.

ESTIMATES OF OUR RESERVES AND ASSOCIATED FUTURE NET CASH FLOWS ARE DEPENDENT
UPON CERTAIN OWNERSHIP ASSUMPTIONS WHICH MAY NOT OCCUR AS ANTICIPATED.

            The estimates of the quantities of our proved undeveloped reserves
and the estimated future net revenues from such reserves is based on certain
assumptions about our ownership in the underlying properties. As a result of the
PVOG participation agreement entered into in December 2003, our ownership
interest in proved undeveloped reserves in the Phase I and Phase

                                       35
<PAGE>

II acreage has been reduced to reflect PVOG's new ownership position. Our
ownership position in wells in Phase II will be reduced as well if PVOG drills
two wells in Phase II and our year-end reserve estimates assume that PVOG will
complete Phase I and all of Phase II. Our reserve estimates will be increased if
PVOG does not complete Phase II.

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. 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.

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

                                       36
<PAGE>

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;

            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 88% of our reserves at
December 31, 2004 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 2004, generally stimulate increased
demand and result in increased prices and unavailability for drilling rigs,
crews, associated supplies, equipment and services. We and PVOG are currently
experiencing difficulty obtaining drilling rigs, crews, associated supplies,
equipment and services because of a recent increases in prices and in activity.
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

                                       37
<PAGE>

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.

            At December 31, 2004, approximately 65% 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 $65 million to develop these reserves, including $15 million in
2005. 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

                                       38
<PAGE>

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

            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

                                       39
<PAGE>

could cause us to be unprotected against some or all of the risk. The occurrence
of an uninsured loss could have a material adverse effect on our financial
condition or results of operations.

GOVERNMENTAL REGULATIONS COULD ADVERSELY AFFECT OUR BUSINESS.

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

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

ENVIRONMENTAL LIABILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

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

            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 AND HAVE
A MORE LIMITED OPERATING HISTORY 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

                                       40
<PAGE>

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.

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

            On April 29, 2004, our Audit Committee of the Board of Directors
approved the dismissal of KPMG, LLP ("KPMG") as our independent public
accountant. On the same day, the Audit Committee approved Smith, Carney & Co.,
p.c. ("Smith Carney") as our independent public accountant for the year 2004.

            KPMG's audit report on our consolidated financial statements as of
and for each of the years ended December 31, 2003 and 2002 did not contain an
adverse opinion or disclaimer of opinion, nor were they qualified or modified as
to uncertainty, audit scope or accounting principals, except as follows:

            KPMG's report on our consolidated financial statements for the year
ended December 31, 2002 contained a separate paragraph stating that "The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern. As discussed in Note L to the financial
statements, the Company is not in compliance with certain of its debt covenants
and has a significant working capital deficiency that raise substantial doubt
about the Company's ability to continue operating as a going concern.
Management's plans in regard to these matters are also described in Note L. The
financial statements do not include any adjustments that might result from the
outcome of this uncertainty."

            KPMG's report on our consolidated financial statements for the year
ended December 31, 2003 contained a separate paragraph stating that "As
discussed in Note A to the consolidated financial statements, GMX Resources Inc.
changed its method of accounting for asset retirement obligations in 2003."

            During the years ended December 31, 2003 and 2002, and through April
29, 2004, there were no disagreements with KPMG on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure which, if not resolved to KPMG's satisfaction, would have caused them
to make reference to the subject matter in connection with their opinion on our
consolidated financial statements for such years.

            During the years ended December 31, 2003 and 2002 and through April
29, 2004, we did not consult Smith Carney with respect to the application of
accounting principles to a specified

                                       41
<PAGE>

transaction, either completed or proposed, or the type of audit opinion that
might be rendered on our consolidated financial statements, or any matters or
reportable events as set forth in Items 304(a)(2)(i) and (ii) of Regulation S-K.

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























                                       42
<PAGE>

                                    PART III

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

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

NAME                     AGE   POSITION CURRENTLY HELD
----------------------   ---   -------------------------------------------------
Ken L. Kenworthy, Jr.     48   President, Chief Executive Officer and Director
Ken L. Kenworthy, Sr.     69   Executive Vice President Secretary, Treasurer,
                               Chief Financial Officer and Director
T.J. Boismier             70   Director
Steven Craig              48   Director
Jon W. "Tucker" McHugh    60   Director
Kyle Kenworthy            43   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 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.

                                       43
<PAGE>

            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 and IPE 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.

            KYLE KENWORTHY became Vice President of Land for the Company in
March, 1999. From 1997 until he joined the Company, he was an independent
petroleum landman, performing contract land services for other oil and gas
companies, and from 1992 to 1997 he was an independent real estate investor and
manager. Prior to that time, he was employed by H&K Exploration and OEXCO Inc.
in various geological, accounting and land management positions. Over a 12 year
period at OEXCO, Mr. Kenworthy helped structure and managed an aggressive
drilling program in Oklahoma City and surrounding areas for over 300 company
operated wells.

            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. and Kyle
Kenworthy.

SIGNIFICANT EMPLOYEES

            Keith Leffel, age 55, 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 47, 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. He worked with Focus Energy for nine years and had
responsibility for 319 producing wells.

CONSULTANT

            In March 2004, the Company engaged Donald Duke to provide
engineering, corporate management and business development consulting assistance
and advisory services. Mr. Duke is president of Duke Resources Co., LLC, an
independent oil and gas production and consulting firm. He has over 32 years of
energy industry management and engineering experience having served as senior
management positions with TGX Corporation, Hadson Petroleum, Santa Fe Minerals
and Andover Oil Company.

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.

                                       44
<PAGE>

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 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 2004,
except for one late filing by Karen M. Kenworthy who inadvertently filed a Form
4 to report a sale of shares one day late.

AUDIT COMMITTEE MATTERS

            During 2004, we had a standing audit committee consisting of Messrs.
Boismier and Craig, both 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. Neither of these individuals qualify as
a "financial expert" as contemplated by the rules of the Securities and Exchange
Commission. These individuals were appointed to our audit committee before the
adoption of the financial expert rules. 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.









                                       45
<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.         2002   $175,000   $30,000        --          $  8,385
 President and Chief          2003    157,500       --         --               ---
 Executive Officer            2004    166,667    20,000        --               ---

Ken L. Kenworthy, Sr.         2002    175,000    30,000        --             8,385
 Executive Vice President,    2003    157,500       --         --               ---
 Secretary, Treasurer and     2004    166,667    20,000        --               ---
 Chief Financial Officer

Kyle Kenworthy                2002     72,000       --         --             5,232
 Vice President--Land         2003     72,000     1,000        --             2,599
                              2004     74,880     4,000        --             2,599
</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
     Kyle Kenworthy.

            The following table shows option grants to the named executive
officers in 2004.

                                      OPTION GRANTS IN LAST FISCAL YEAR

                   NUMBER OF
                SHARES OF COMMON   % OF TOTAL OPTIONS   EXERCISE OR
                STOCK UNDERLYING  GRANTED TO EMPLOYEES   BASE PRICE   EXPIRATION
     NAME        OPTIONS GRANTED     IN FISCAL YEAR     ($/SHARE)(1)     DATE
--------------  ----------------  --------------------  ------------  ----------
Kyle Kenworthy       5,000                2.5%           $   3.00     01-12-2014
                     5,000                2.5%           $   6.10     12-13-2014

------------
(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 2004 or
outstanding at year-end for the named executive officers.


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

                                          NUMBER OF SECURITIES              VALUE OF
                                         UNDERLYING UNEXERCISED     UNEXERCISED IN-THE-MONEY
                                               OPTIONS AT                  OPTIONS AT
                  SHARES                   DECEMBER 31, 2004            DECEMBER 31, 2004
                 ACQUIRED     VALUE    --------------------------  --------------------------
NAME            ON EXERCISE  REALIZED  EXERCISABLE  UNEXERCISABLE  EXERCISABLE  UNEXERCISABLE
--------------  -----------  --------  -----------  -------------  -----------  -------------
<S>                 <C>         <C>       <C>           <C>          <C>            <C>
Kyle Kenworthy      N/A         N/A       15,000        15,000       $22,088        $2,463
</TABLE>


                                       46
<PAGE>

COMPENSATION OF DIRECTORS

            Nonemployee directors, T. J. Boismier, Steven Craig and Jon Tucker
McHugh receive $1,000 for each board and $500 for each committee meeting which
they attend. We have also granted options to our nonemployee directors. Mr.
Boismier received an option on February 12, 2001 to purchase 10,000 shares of
common stock at a price of $8.00 per share (the initial public offering price of
GMX's units) which will vest at a rate of 25% per year for each year of
continued service. Mr. Boismier received an additional option on March 16, 2001
(when GMX's units split into common stock and warrants) to purchase 5,000 shares
of common stock at a price of $4.03 per share (the market price of our common
stock on the date of grant), also vesting at 25% per year for each year of
continued service. Mr. Craig received an option on September 10, 2001 to
purchase 10,000 shares of common stock at a price of $5.00 which also will vest
at a rate of 25% per year for each year of continued service. No options were
granted in 2002 or 2003. On January 12, 2004, Mr. Boismier and Mr. Craig each
received options to purchase 10,000 shares of common stock at $3.00 per share
vesting at 25% per year of each year of continued service. On December 13, 2004,
Mr. Boismier and Mr. Craig also received 10,000 additional options at $6.10. Mr.
McHugh 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 OWNERSHIP AND MANAGEMENT

            The following table sets forth certain information regarding the
beneficial ownership of our common stock as of March 22, 2005, 2005, by (i) each
person or group of affiliated persons known to be the beneficial owner of more
than 5% of our outstanding common stock; (ii) each of our directors; (iii) each
of our executive officers; and (iv) all of our directors and executive officers
as a group.

            As of March 22, 2005, there were 8,201,587 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.



BENEFICIAL OWNER                            NUMBER OF SHARES   PERCENT OF TOTAL
----------------                            ----------------   ----------------
Ken L. Kenworthy, Jr.(1)(2)..............         902,018            11.1%
Karen Kenworthy(2)(6)....................         744,990             9.2%
Ken L. Kenworthy, Sr.(2).................         967,324            11.9%
Newton Family Group(7)...................         900,000            11.1%
T. J. Boismier (3).......................          22,500                *
Steven Craig(4)..........................          10,000                *
Kyle Kenworthy(5)........................          18,750                *
Jon W. McHugh............................               0                *
All executive officers and directors
 as a group(6 persons)...................       1,920,592            23.4%
-----------------
            * Less than 1%.

(1)  Shares owned by Mr. Kenworthy, Jr. exclude 744,990 shares owned by his wife
     as to which he disclaims beneficial ownership.

                                       47
<PAGE>

(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 2,500 shares which Mr. Boismier has the right to acquire upon
     exercise of Class A warrants and 20,000 shares he has the right to acquire
     on exercise of options exercisable within 60 days.

(4)  Includes 10,000 shares which Mr. Craig has the right to acquire on exercise
     of options exercisable within 60 days.

(5)  Includes 18,750 shares which Mr. Kenworthy has the right to acquire on
     exercise of options exercisable within 60 days.

(6)  Shares owned by Karen Kenworthy exclude 902,018 shares owned by her husband
     Ken L. Kenworthy, Jr., as to which she disclaims beneficial ownership.

(7)  This ownership information is based on information provided by the Newton
     Family Group. The Newton Family Group consists of William C. Newton and
     Gloria A. Newton, husband and wife, Newton Discretionary Trust, as to which
     William C. Newton is the sole trustee; 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 775,000 shares beneficially owned by Newton Investment Partners
     and 100,000 shares that may be acquired upon the exercise of warrants held
     by Newton Investment Partners. The business address of the Newton Family
     Group is c/o Newton Corporation, 660 East Broadway, Jackson Hole, Wyoming
     83001.

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.

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 KPMG for the year 2003:

                                                        FEES BILLED
                                                  ----------------------
            TYPE                                     2003         2004
            ----                                  ---------    ---------
            Audit fees                            $  65,000    $  50,000
            Audit related fees                         --            --
            Tax fees                                   --         15,000
            All other fees                             --          9,505
                                                  ---------    ---------
                 Total                            $  65,000    $  74,505
                                                  =========    =========

                                       48
<PAGE>

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






























                                       49
<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 31, 2005                  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.


      SIGNATURES                         TITLE                         DATE
--------------------------------------------------------------------------------

/s/ Ken L. Kenworthy, Jr.      President and Director             March 31, 2005
--------------------------     (Principal Executive Officer)
Ken L. Kenworthy, Jr.

/s/ Ken L. Kenworthy, Jr.      Executive Vice President, Chief    March 31, 2005
--------------------------     Financial Officer and Director
Ken L. Kenworthy, Sr.          (Principal Financial Officer)

/s/ T. J. Boismier             Director                           March 31, 2005
--------------------------
T. J. Boismier

/s/ Steven Craig               Director                           March 31, 2005
--------------------------
Steven Craig

/s/ Jon W. McHugh              Director                           March 31, 2005
--------------------------
Jon W. McHugh


                                       50
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Reports of Independent Registered Public Accounting Firms ................  F-2

Consolidated Balance Sheets, December 31, 2003 and 2004 ..................  F-4

Consolidated Statements of Operations, Years Ended
  December 31, 2003 and 2004 .............................................  F-5

Consolidated Statements of Changes in Shareholders' Equity,
  Years Ended December 31, 2003 and 2004 .................................  F-6

Consolidated Statements of Cash Flows, Years Ended
  December 31, 2003 and 2004 .............................................  F-7

Notes to Consolidated Financial Statements ...............................  F-8

























                                       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 the related consolidated
statements of operations, changes in shareholders' equity, and cash flows for
the year 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 audit.

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 managements, as well as
evaluating the overall financial statement presentation. We believe that our
audit 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 the results of their operations and
their cash flows for the year then ended, in conformity with U.S. generally
accepted accounting principles.

                                                   Smith, Carney & Co., p.c.



Oklahoma City, Oklahoma
February 18, 2005



                                       F-2
<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, 2003 and the related consolidated
statements of operations, changes in shareholders' equity, and cash flows for
the year 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 misstatement. 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, 2003 and the results of their operations and
their cash flows for the year then ended, in conformity with U.S. generally
accepted accounting principles.

As discussed in Note A to the consolidated financial statements, GMX Resources
Inc. changed its method of accounting for asset retirement obligations in 2003.

                                              KPMG LLP




Oklahoma City, Oklahoma
April 6, 2004


                                       F-3
<PAGE>
                       GMX RESOURCES INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS

                                                            DECEMBER 31,
                                                   ----------------------------
                                                       2003            2004
                                                   ------------    ------------
                                     ASSETS
CURRENT ASSETS:
  Cash and cash equivalents                        $    637,522    $    862,546
  Accounts receivable--interest owners                  299,442          96,248
  Accounts receivable--oil and gas revenues             432,844       1,501,073
  Inventories                                           235,004         204,442
  Prepaid expenses and other current assets              11,608         108,447
                                                   ------------    ------------
    Total current assets                              1,616,420       2,772,756
                                                   ------------    ------------

OIL AND GAS PROPERTIES, AT COST, BASED
ON THE FULL COST METHOD OF ACCOUNTING
FOR OIL AND GAS PROPERTIES                           32,449,096      42,452,970
  Less accumulated depreciation, depletion,
  and amortization                                   (4,788,779)     (6,496,210)
                                                   ------------    ------------
                                                     27,660,317      35,956,760
                                                   ------------    ------------

OTHER PROPERTY AND EQUIPMENT                          3,200,345       3,515,422
  Less accumulated depreciation                        (991,889)     (1,308,358)
                                                   ------------    ------------
                                                      2,208,456       2,207,064
                                                   ------------    ------------
OTHER ASSETS                                             16,013          54,883
                                                   ------------    ------------
    TOTAL ASSETS                                   $ 31,501,206    $ 40,991,463
                                                   ============    ============


                      LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts payable                                 $  1,134,500    $  2,321,517
  Accrued expenses                                       64,887         134,718
  Accrued interest                                       29,703            --
  Revenue distributions payable                         285,382         274,862
  Current portion of long-term debt                   1,060,000         433,933
                                                   ------------    ------------
    Total current liabilities                         2,574,472       3,165,030
                                                   ------------    ------------
LONG-TERM DEBT, LESS CURRENT PORTION                  5,630,000       3,328,361
                                                   ------------    ------------
OTHER LIABILITIES                                       678,169       2,091,216
                                                   ------------    ------------

SHAREHOLDERS' EQUITY:
  Preferred stock, par value $.01 per share,
  10,000,000 shares authorized; none issued;
  Common stock, par value $.001 per share -
  authorized 50,000,000 shares; issued and
  outstanding 6,575,000 shares in 2003 and
  8,053,539 shares in 2004                                6,575           8,054
Additional paid-in capital                           20,959,973      29,305,012
Retained earnings                                     1,652,017       3,093,790
                                                   ------------    ------------
Total shareholders' equity                           22,618,565      32,406,856
                                                   ------------    ------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY         $ 31,501,206    $ 40,991,463
                                                   ============    ============


          See accompanying notes to consolidated financial statements.

                                       F-4
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS

                                                       YEAR ENDED DECEMBER 31,
                                                     --------------------------
                                                         2003           2004
                                                     -----------    -----------

REVENUE
  Oil and gas sales                                  $ 5,367,370    $ 7,689,882
  Interest income                                          2,592         14,498
  Other income                                            18,832        129,330
                                                     -----------    -----------
    Total revenue                                      5,388,794      7,833,710
                                                     -----------    -----------

EXPENSES
  Lease operations                                       850,034      1,261,109
  Production and severance taxes                         384,069        518,721
  Depreciation, depletion and amortization             1,549,678      2,043,485
  Interest                                               439,313        558,504
  General and administrative                           1,578,865      1,985,912
                                                     -----------    -----------
    Total expenses                                     4,801,959      6,367,731
                                                     -----------    -----------

    Income before income taxes                           586,835      1,465,979

INCOME TAXES                                                --           24,206
                                                     -----------    -----------

  Net income before cumulative effect of a change
  in accounting principle                            $   586,835    $ 1,441,773
                                                     -----------    -----------

  Cumulative effect of a change in accounting
  principle                                              (51,834)          --
                                                     -----------    -----------

  Net income                                         $   535,001    $ 1,441,773
                                                     ===========    ===========

  EARNINGS PER SHARE--Before Cumulative Effect       $      0.09    $      0.19
  EARNINGS (LOSS) PER SHARE--Cumulative Effect             (0.01)          --
                                                     -----------    -----------
  EARNINGS PER SHARE--Basic and Diluted              $      0.08    $      0.19
                                                     ===========    ===========
  WEIGHTED AVERAGE COMMON SHARES - Basic               6,560,000      7,396,880
                                                     ===========    ===========
  WEIGHTED AVERAGE COMMON SHARES - Diluted             6,560,000      7,491,778
                                                     ===========    ===========

          See accompanying notes to consolidated financial statements.

                                       F-5

<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
            CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
                     YEARS ENDED DECEMBER 31, 2003 AND 2004
<TABLE><CAPTION>
                                                                                                        ACCUMULATED
                                                                                                           OTHER
                                               COMMON STOCK             ADDITIONAL                     COMPREHENSIVE      TOTAL
                                       ----------------------------      PAID-IN         RETAINED         INCOME       SHAREHOLDERS'
                                          SHARES          AMOUNT         CAPITAL         EARNINGS         (LOSS)          EQUITY
                                       ------------    ------------    ------------    ------------    ------------    ------------
<S>                                       <C>          <C>             <C>             <C>             <C>             <C>
BALANCE AT DECEMBER 31, 2002              6,550,000    $      6,550    $ 20,905,197    $  1,117,016    $   (421,300)   $ 21,607,463

Compensation from option grant                 --              --            29,801            --              --            29,801
Options exercised                            25,000              25          24,975            --              --            25,000
Adjustment from derivative losses
reclassified into oil and gas sales            --              --              --           438,400         438,400
                                                                                                                       ------------
Change in fair value of derivative
instruments                                    --              --              --           (17,100)        (17,100)
                                                                                                                       ------------
Net income                                     --              --           535,001            --           535,001
                                                                                                                       ------------
Total comprehensive income                     --              --              --              --           956,301
                                                                                                                       ------------
                                       ------------    ------------    ------------    ------------    ------------    ------------
BALANCE AT DECEMBER 31, 2003              6,575,000    $      6,575    $ 20,959,973    $  1,652,017    $       --        22,618,565
                                       ------------    ------------    ------------    ------------    ------------    ------------

Options Exercised                            15,000              15          14,985            --              --            15,000
Redeemed & Cancelled Warrants                  --              --          (118,712)           --              --          (118,712)
Warrants Granted                               --              --           257,250            --              --           257,250
Warrants Exercised                          163,540             164         177,398            --              --           177,562
Shares Issued                             1,300,000           1,300       8,014,118            --              --         8,015,418
Net income                                     --              --              --         1,441,773            --         1,441,773
                                       ------------    ------------    ------------    ------------    ------------    ------------

BALANCE AT DECEMBER 31, 2004              8,053,540    $      8,054    $ 29,305,012    $  3,093,790    $       --      $ 32,406,856
                                       ============    ============    ============    ============    ============    ============
</TABLE>

          See accompanying notes to consolidated financial statements.

                                       F-6
<PAGE>

                       GMX RESOURCES INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                       YEAR ENDED DECEMBER 31,
                                                      -------------------------
                                                          2003          2004
                                                      -----------   -----------

CASH FLOWS DUE TO OPERATING ACTIVITIES
  Net income                                          $   535,001   $ 1,441,773
  Adjustments to reconcile net income to net cash
   provided by operating activities:
    Compensation-stock options                             29,801          --
    Depreciation, depletion, and amortization           1,549,678     2,043,485
    Cumulative effect of change in accounting
     principle, net of tax                                 51,834          --
    Accretion of asset retirement obligation               22,521        24,323
    Amortization of loan fees                                --         326,762
    Decrease (increase) in:
      Accounts receivable                                  84,188      (865,035)
      Inventory and prepaid expenses                        1,701      (431,908)
      Other assets                                         41,633          --
    Increase (decrease) in:
      Accounts payable                                 (1,292,215)    1,187,017
      Accrued expenses and other liabilities              112,615        40,128
      Revenue distributions payable                      (122,467)      (58,067)
                                                      -----------   -----------

      Cash provided by operating activities             1,014,290     3,708,478
                                                      -----------   -----------

CASH FLOWS DUE TO INVESTING ACTIVITIES
  Additions to oil and gas properties                    (236,617)   (8,567,690)
  Purchase of property and equipment                         --        (334,577)
  Proceeds from sale of oil and gas properties            700,932          --
                                                      -----------   -----------
Cash provided by (used in) investing activities           464,315    (8,902,267)
                                                      -----------   -----------

CASH FLOWS DUE TO FINANCING ACTIVITIES
Advance on borrowings                                        --       3,872,457
Payments on debt                                       (1,410,000)   (6,800,162)
Proceeds from sale of stock                                25,000     8,346,518
                                                      -----------   -----------
      Cash provided by (used in) financing
       activities                                      (1,385,000)    5,418,813
                                                      -----------   -----------

NET INCREASE IN CASH AND CASH EQUIVALENTS                  93,605       225,024

CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD                                       543,917       637,522
                                                      -----------   -----------

CASH AND CASH EQUIVALENTS AT END OF PERIOD            $   637,522   $   862,546
                                                      ===========   ===========

CASH PAID FOR INTEREST                                $   376,585   $   261,445
                                                      ===========   ===========

CASH PAID FOR INCOME TAXES                            $      --     $    24,206
                                                      ===========   ===========

          See accompanying notes to consolidated financial statements.

                                       F-7
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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 Expedition Natural Resources, Inc.
Endeavor Pipeline, Inc. owns and operates natural gas gathering facilities in
East Texas. Expedition Natural Resources, Inc. owns undeveloped leases,
primarily in East Texas. 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. In February 1998, the
Company purchased, for approximately $6,000,000, oil and gas properties and
commenced operations. 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 plans to utilize the 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.

The December 2003 sale of an interest in East Texas properties did not result in
a gain or loss. All proceeds from the sale were applied to the full cost pool.

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

                                       F-8
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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
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 its 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, 2003 or 2004.

CAPITALIZED INTEREST: Interest of $20,729 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 2004.

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 has periodically entered
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-9
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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.

                                                        2003            2004
                                                   -------------   -------------
     Options excluded from dilution calculation       64,000           41,000
     Range of exercise prices                      $3.50 - $8.00   $5.00 - $8.00
     Weighted average exercise price                   $6.00           $6.75

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, GMX has elected to continue to apply the intrinsic
value based method of accounting described above.

                                      F-10
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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

                                                                WEIGHTED AVERAGE
                                              NUMBER OF SHARES   EXERCISE PRICE
                                              ----------------  ----------------
     Balance as of December 31, 2002               140,000          $   5.65
          Granted                                  100,000              1.00
          Exercised                                (25,000)             1.00
          Forfeited                                (76,000)             5.62
          Expired                                      --                --
                                              ----------------  ----------------
     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
                                              ----------------  ----------------

At December 31, 2004, the range of exercise prices and weighted-average
remaining contractual life of outstanding options was $1.00 to $8.00 and ten
years, respectively.

At December 31, 2004, the number of options exercisable was 314,000 and the
weighted-average exercise price of those options was $3.67.

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.

                                                        2003            2004
                                                    -----------     -----------
     Net earnings as reported                       $   535,001     $ 1,441,773

     Add: Stock-based compensation recognized            29,801             --

     Deduct: Pro forma stock-based compensation,
     net of tax                                         (79,081)       (316,085)
                                                    -----------     -----------
     Pro forma net earnings                         $   485,721     $ 1,125,689
                                                    ===========     ===========
     Pro forma earnings per share - basic           $      0.07            0.15
                                                    ===========     ===========
     Pro forma earnings per share - diluted         $      0.07            0.15
                                                    ===========     ===========


For the January 2004 options, fair value was determined using the Black Scholes
option pricing model with the following assumptions: expected dividend yield of
0%, risk-free interest rate of 1%, expected volatility of 116%, and an expected
term of 10 years. For the December 2004 options, fair value was determined using
the Black-Scholes option pricing model with the following assumptions: expected
dividend yield of 0%, risk-free interest rate of 1%, expected volatility of
137%, and an expected term of 10 years.

                                      F-11
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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.

RECLASSIFICATIONS: 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, 2003 and 2004.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS: In June 2001, FASB Statement No. 143,
Accounting for Asset Retirement Obligations, was issued. Statement 143 required
the Company to record the fair value of an asset retirement obligation as a
liability in the period in which it incurs a legal obligation associated with
the retirement of tangible long lived assets that result from the acquisition,
construction, development, and/or normal use of the assets. The Company also
recorded a corresponding asset that is depreciated over the life of the asset.
Subsequent to the initial measurement of the asset retirement obligation, the
obligation will be adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation.
The Company was required to adopt Statement 143 on January 1, 2003 and
recognized, as the fair value of the asset retirement obligations, $281,516. Due
to the adoption of Statement 143, the Company recognized a charge in 2003, for
this cumulative effect of change in accounting principle, of $51,834.

Below is a reconciliation of the beginning and ending aggregate carrying amount
of the Company's asset retirement obligations.




                                      F-12
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

            Balance as of December 31, 2002                  $         --
            Initial adoption entry                                 281,516
            Liabilities incurred                                       --
            Liabilities settled                                        --
            Accretion expense                                       22,521
                                                             -------------
            Balance as of December 31, 2003                  $     304,037
            Liabilities incurred                                    40,493
            Liabilities settled                                   (249,867)
            Accretion expense                                       24,323
            Increase due to revisions (1)                        1,645,645
                                                             -------------
            Balance as of December 31, 2004                  $   1,764,631
                                                             =============

            (1) Revisions were due to the increase in market prices for services
            related to plugging a well, the current inflation rate and interest
            rate.

In addition, on a pro forma basis as required by SFAS No. 143, if the Company
had applied the provisions of SFAS No. 143 as of January 1, 2002, the amount of
asset retirement obligations would have been approximately $250,000, with no
material impact on results of operations.

In September 2004, the staff of the SEC issued Staff Accounting Bulletin No. 106
(SAB 106) to express the staff's views regarding application of FAS 143,
"Accounting for Asset Retirement Obligations," by oil and gas producing
companies following the full cost accounting method. SAB 106 addressed the
computation of the full cost ceiling test to avoid double-counting asset
retirement costs, the disclosures a full cost accounting company is expected to
make regarding the impacts of FAS 143, and the amortization of estimated
dismantlement and abandonment costs that are expected to result from future
development activities. We adopted the accounting and disclosures described in
SAB 106 as of the third quarter of 2004 and did not have a material impact on
our financial position of the Company, or our results of operations.

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
interim and annual periods that begin after June 15, 2005 and will be adopted by
the Company in the third quarter of 2005. See "Stock Options" above for a
disclosure of the effect on net income and earnings per share for the years 2003
and 2004 if we had applied the fair value recognition provisions of FAS 123 to
stock-based employee compensation.

                                      F-13
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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. We do not expect this statement to have a
material impact on results of operations or financial condition.

In November 2004, the FASB issued Statement on Financial Accounting Standards
No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4," which
clarifies the types of costs that should be expensed rather than capitalized as
inventory. The provisions of FAS 151 are effective for years beginning after
June 15, 2005. We do not expect this statement to have a material impact on
results of operations or financial condition.

NOTE B--PROPERTY AND EQUIPMENT

Property and equipment included the following:

                                                           DECEMBER 31,
                                                   ----------------------------
                                                       2003            2004
                                                   ------------    ------------
     Oil and gas properties:
          Subject to amortization                  $ 31,219,309    $ 41,893,564
          Not subject to amortization:
             Acquired in 2004                              --           447,786
             Acquired in 2003                            57,565            --
             Acquired in 2002                            76,829          76,829
             Acquired in 2001                           853,258          34,791
             Acquired in 2000                            93,195            --
             Acquired in 1999                              --              --
             Acquired in 1998                           148,940            --
          Accumulated depreciation, depletion,
          and amortization                           (4,788,779)     (6,496,210)
                                                   ------------    ------------
             Net oil and gas properties              27,660,317      35,956,760
                                                   ------------    ------------
     Other property and equipment                     3,200,345       3,515,422
     Less accumulated depreciation                     (991,889)     (1,308,358)
                                                   ------------    ------------

            Net other property and equipment          2,208,456       2,207,064
                                                   ------------    ------------
              Property and equipment, net of
                accumulated Depreciation,
                depletion, and amortization        $ 29,868,773    $ 38,163,824
                                                   ============    ============

                                      F-14
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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

                                                         FOR THE YEAR ENDED
                                                             DECEMBER 31,
                                                      -------------------------
                                                          2003          2004
                                                      -----------   -----------
     Depreciation, depletion, and amortization
       of oil and gas properties                      $ 1,214,361   $ 1,707,431
     Depreciation of other property and equipment         335,317       336,054
                                                      -----------   -----------
                    Total                             $ 1,549,678   $ 2,043,485
                                                      ===========   ===========

NOTE C--LONG-TERM DEBT

                                                             DECEMBER 31,
                                                      -------------------------
                                                          2003          2004
                                                      -----------   -----------
     Note payable to bank, maturity date
     of September, 2006, bearing a variable
     interest rate (5.00% and 5.25% as of
     December 31, 2003 and 2004, respectively)
     collateralized by producing oil and gas
     properties                                       $ 6,690,000   $ 1,849,837

     Joint venture partner project (financing,
     non-recourse, no interest rate)                          --      1,912,457
                                                      -----------   -----------
                                                        6,690,000     3,762,294
      Current portion                                   1,060,000       433,933
                                                      -----------   -----------
            Long Term                                 $ 5,630,000   $ 3,328,361

      Maturities of long-term debt are as follows:

                                            YEAR        AMOUNT
                                        -----------   -----------
                                            2005      $   433,934
                                            2006        2,558,173
                                            2007          770,187
                                                      -----------
                                                      $ 3,762,294
                                                      ===========

2000 CREDIT FACILITY

On October 31, 2000, 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 $15,000,000 (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 up to plus 1% depending on the level of borrowings relative to the
Borrowing Base. The credit facility requires payment of an annual facility fee
equal to 1/2% on the unused amount of the Borrowing Base. The Company is
obligated to make principal

                                      F-15
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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. The credit facility has been amended on several occasions to waive
non-payment default or to extend the maturity, most recently in June to extend
the maturity to September 1, 2006. On October 25, 2004, the bank increased the
Borrowing Base to $10,000,000, with monthly commitment reduction of $120,000. At
December 31, 2004, the Company had borrowed $1,849,837 under the credit
facility.

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.

SUBORDINATED DEBT

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. For accounting purposes the
fair value of the in-the-money warrants increased the effective interest rate
over the term of the notes. In connection with this transaction, the lender
under the Company's bank credit facility agreed to the Company's incurrence of
additional debt and entered into an intercreditor and subordination agreement
with the noteholders pursuant to which the noteholders subordinated their rights
to payment to the rights of the bank under the credit facility. Principal
reductions of $100,000 per year on the subordinated notes were permitted in 2005
and 2006 subject to certain conditions being met under the terms of the credit
facility agreements. The Company repaid the notes in June of 2004 with proceeds
of bank borrowings.

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, 2004, the Present
Value of GMX's interest in the wells funded in this manner was $2.8 million.

NOTE D--INCOME TAXES

Intangible development costs are 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.

                                      F-16
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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

At December 31, 2004, the Company had the following carryforwards available to
reduce future income taxes:

            Net Operating Losses:
                 Federal                              $27,026,000
                 State                                  1,100,000
            Statutory depletion                         3,710,000

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.
Statutory depletion carryforwards do not expire.

As of December 31, 2004, a deferred tax liability of $10,287,000 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 $10,516,000 was primarily the result of the net
operating loss and statutory depletion carryforwards. As of December 31, 2004,
the Company recognized a valuation allowance of $229,000. Management of the
Company determined that based upon current taxable income and financial
conditions, it is likely that the Company will not be able to utilize all of its
net operating loss carryforwards prior to their expiration.


                                                             DECEMBER 31,
                                                      -------------------------
                                                          2003          2004
                                                      -----------   -----------
     Deferred tax assets:
             Net operating loss carry forwards          7,622,000     9,255,000
             Statutory depletion carry forwards           876,000     1,261,000
                                                      -----------   -----------
                      Total                             8,498,000    10,516,000
                                                      -----------   -----------
     Deferred tax liability:
             Property, plant and equipment             (7,896,000)  (10,287,000)
             Valuation allowance                         (602,000)     (229,000)
                                                      -----------   -----------
                      Total                            (8,498,000)  (10,516,000)
                                                      -----------   -----------
     Net deferred tax asset                                   --            --
                                                      ===========   ===========


As of December 31, 2003, the Company's deferred tax liability of $7,896,000 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 deferred tax asset of $8,498,000 was primarily the result of the
Company's 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:

                                      F-17
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

                                                         FOR THE YEAR ENDED
                                                             DECEMBER 31,
                                                      -------------------------
                                                          2003          2004
                                                      -----------   -----------
     U.S. statutory tax rate                               34%           34%
     Statutory depletion                                  (93)          (25)
     Change in valuation allowance                         58           (24)
     Other                                                  1            16
                                                      -----------   -----------
     Effective income tax rate                             --             1
                                                      ===========   ===========

NOTE E--COMMITMENTS AND CONTINGENCIES

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

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, 2004.

Year Ending December 31:

     2005                                             $   100,357
     2006                                                 100,178
     2007                                                  23,846
     2008                                                   8,974
                                                      -----------
             Total                                    $   233,355
                                                      ===========

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

     2003                                             $   195,468
     2004                                                 153,613


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

                                      F-18
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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.

On April 15, 2003, the Company granted an option to a consultant to purchase
100,000 shares of common stock at a price of $1.00 per share. Options on 25,000
shares were vested on the date of the grant and the balance vest 25,000 on July
15, 2003, 25,000 on October 15, 2003 and 25,000 on January 1, 2004. The fair
value of the stock options granted was recognized in 2003.

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.

The Company's Class A warrants allow holders to purchase common shares of the
Company for $12.00 per share until February 12, 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.

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, 2003 and 2004 were as follows:

                                      F-19
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

                                                          2003        2004
                                                          ----        ----

     Teppco Crude (Oil)                                    99%         93%
     CrossTex Energy Services, Inc. (Gas)                  83%         63%
     Penn Virginia Oil & Gas (Gas)                         --          21%
     Duke Energy (Gas)                                     --          10%

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.






















                                      F-20
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004


NOTE I--OIL AND GAS OPERATIONS (UNAUDITED)

Capitalized costs related to the Company's oil and gas producing activities as
of December 31, 2003 and 2004 are:
                                                          2003          2004
                                                      -----------   -----------
     Unproved properties                              $ 1,229,787   $   559,407
     Producing properties                              31,219,309    41,893,563
                                                      -----------   -----------
                                                       32,449,096    42,452,970
     Less accumulated depreciation, depletion, and
        Amortization                                   (4,788,779)   (6,496,210)
                                                      -----------   -----------
                    Net capitalized costs             $27,660,317   $35,956,760
                                                      ===========   ===========

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 2003 and 2004 are as follows:

                                                          2003          2004
                                                      -----------   -----------
     Property acquisition costs - proved              $    57,575   $       --
     Property acquisition costs - unproved                  5,212       851,617
     Development costs                                    175,840     9,152,257
                                                      -----------   -----------
                                                      $   238,627   $10,003,874
                                                      ===========   ===========

Developments costs above include non-cash Asset Retirement Costs of $1,436,184.


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 2003 and 2004 include revenues and
expenses associated directly with oil and gas producing activities.

                                                          2003          2004
                                                      -----------   -----------
     Oil and gas sales                                $ 5,367,370   $ 7,689,882
     Production costs                                  (1,211,582)   (1,779,830)
     Depreciation, depletion and amortization          (1,214,779)   (1,707,431)
     Income tax expense                                  (733,670)   (1,047,075)
                                                      -----------   -----------
     Results of operations for oil and gas
          producing activities                        $ 2,207,339   $ 3,155,546
                                                      ===========   ===========

                                      F-21
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

NOTE J--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,
2003 and 2004, all of the Company's oil and gas reserves were located in the
United States.

                                                          OIL            GAS
                                                        (MBBLS)        (MMCF)
                                                      -----------   -----------
     DECEMBER 31, 2003
        Proved reserves, beginning of period                1,664        56,682
        Extensions, discoveries, and other additions          --            --
        Production                                            (35)         (917)
        Sale of reserves in-place                            (251)      (11,414)
        Revisions of previous estimates                       (55)          678
                                                      -----------   -----------
        Proved reserves, end of period                      1,323        45,029
                                                      ===========   ===========
        Proved developed reserves:
            Beginning of period                               604        16,501
                                                      ===========   ===========
            End of period                                     568        18,277
                                                      ===========   ===========
     DECEMBER 31, 2004
        Proved reserves, beginning of period                1,323        45,029
        Extensions, discoveries, and other additions           51        14,644
        Production                                            (30)       (1,049)
        Sale of reserves in-place                             --            --
        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
                                                      ===========   ===========

                                      F-22
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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

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

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

                                                    DECEMBER 31,   DECEMBER 31,
                                                        2003           2004
                                                    -----------    -----------
                                                   (IN THOUSANDS) (IN THOUSANDS)
     Future cash inflows                            $   300,514    $   375,427
     Future production costs                            (77,608)       (94,338)
     Future development costs                           (44,557)       (66,811)
     Future income tax provisions                       (58,158)       (48,926)
                                                    -----------    -----------

        Net future cash inflows                         120,191        165,352
     Less effect of a 10% discount factor               (72,216)      (101,120)
                                                    -----------    -----------
        Standardized measure of discounted future
          net cash flows                            $    47,975    $    64,231
                                                    ===========    ===========

Oil and condensate prices were based on an equivalent base price of $43.45 per
barrel for benchmark posted West Texas Intermediate Crude Oil at closing on
December 31, 2004. Adjustments to the base price were made to each lease to
adjust the base price for crude oil quality, contractual agreements, and
regional price variations. The average oil price used in the reserve estimates
was $42.02 per barrel. Natural gas prices were based on an equivalent base price
of $6.149 per million British thermal unit (mmbtu) for the composite Henry Hub
Spot Market benchmark price at closing on December 31, 2004. Adjustments to the
base price were made to each lease to adjust the base price for quality,
contractual agreements, and regional price variations. The average natural gas
price used in the reserve estimates was $5.69 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.

                                      F-23
<PAGE>

                      GMX RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                           DECEMBER 31, 2003 AND 2004

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


                                                    DECEMBER 31,   DECEMBER 31,
                                                        2003           2004
                                                    -----------    -----------
                                                   (IN THOUSANDS) (IN THOUSANDS)

Standardized measure, beginning of year                  54,312         47,975
Sales of oil and gas, net of production costs            (4,156)        (5,910)
Net changes in prices and production costs               11,782          4,409
Extensions and discoveries, net of future
development costs                                           --          18,949
Development costs that reduced future
development costs                                           --           6,863
Revisions of quantity estimates                             646         (4,035)
Sales of reserves in place                              (16,434)           --
Accretion of discount                                     8,061          1,149
Other                                                    (9,322)        (9,379)
Net changes in income taxes                               3,086          4,210
                                                    -----------    -----------
Standardized measure, end of year                        47,975         64,231
                                                    ===========    ===========















                                      F-24
<PAGE>
                                  EXHIBIT INDEX
                                  -------------

EXHIBIT NO.     DESCRIPTION OF EXHIBIT

  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 and Restated Bylaws of GMX Resources, Inc. (Incorporated
                by reference to Exhibit 3.2 to the Quarterly Report on Form
                10-QSB for the period ending September 30, 2004)

  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)

  10.2*         Stock Option Plan, as amended (Incorporated by reference to
                Exhibit 10.2 to the Registration Statement on Form SB-2, File
                No. 333-49328)

  10.3          Restated Credit Agreement dated October 31, 2000 with Local
                Oklahoma Bank, N.A. (Incorporated by reference to Exhibit 10.3
                to the Registration Statement on Form SB-2, File No. 333-63586)

  10.3(a)       First Amendment to Credit Agreement (Incorporated by reference
                to Exhibit 10.3(a) to the Registration Statement on Form SB-2,
                File No. 333-63586)

  10.3(b)       Second Amendment to Credit Agreement dated May 28, 2002
                (Incorporated by reference to Exhibit 10.1 to Form 10-QSB for
                the quarter ended June 30, 2002)

  10.3(c)       Third Amendment to Credit Agreement dated August 16, 2002
                (Incorporated by reference to Exhibit 10.3 to Annual Report on
                Form 10-KSB for the year ended December 31, 2002)

  10.4(c)       Fourth Amendment to Credit Agreement effective August 31, 2003
                (Incorporated by reference to Exhibit 10.1 to Quarterly Report
                as Form 10-QSB for the quarter ended September 30, 2003)

<PAGE>

  10.4(d)       Fifth Amendment to Credit Agreement dated as of January 16,
                2004, (Incorporated by reference to Current Report on Form 8-K
                dated January 16, 2004)

  10.4(e)       Sixth Amendment to Credit Agreement dated as of March 1, 2004
                (Incorporated by reference to Exhibit 10.4(e) to Annual Report
                on Form 10-KSB for the year ended December 31, 2003)

  10.4(f)       Letter dated April 14, 2004 from Local Oklahoma Bank.
                (Incorporated by reference to Exhibit 10.4(e) to Annual Report
                on Form 10-KSB for the year ended December 31, 2003)

  10.4(g)       Seventh Amendment to Credit Agreement dated as of June 18, 2004
                (Incorporated by reference to Exhibit 10.3 to Current Report on
                Form 8-K dated June 18, 2004)

  10.5          Form of Director Indemnification Agreement (Incorporated by
                reference to Exhibit 10.5 to the Registration Statement on Form
                SB-2, File No. 333-49328)

  10.6          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)

  10.6(a)       First Amendment dated February 27, 2004 to Participation
                Agreement (Incorporated by reference to Exhibit 10.1 to Current
                Report on Form 8-K dated August 10, 2004

  10.6(b)       Second Amendment dated March 9, 2004 to Participation Agreement
                (Incorporated by reference to Exhibit 10.2 to Current Report on
                Form 8-K dated August 10, 2004)

  10.6(c)       Third Amendment dated April 6, 2004 to Participation Agreement
                (Incorporated by reference to Exhibit 10.3 to Current Report on
                Form 8-K dated August 10, 2004)

  10.6(d)       Fourth Amendment dated August 11, 2004 Participation Agreement
                (Incorporated by reference to Exhibit 10.4 to Current Report on
                Form 8-K dated August 10, 2004)

  10.6(e)       Fifth Amendment dated March 2, 2005 to Participation Agreement

  10.7          Subordinated Note Purchase Agreement dated January 16, 2004,
                among GMX Resources Inc. and the Investors named therein
                (Incorporated by reference to Current Report on Form 8-K dated
                January 16, 2004)

<PAGE>

  10.8          Intercreditor and Subordination Agreement dated January 16,
                2004, among GMX Resources Inc., the Investors named therein and
                Local Oklahoma Bank (Incorporated by reference to Current Report
                on Form 8-K dated January 16, 2004)

  10.9          Warrant Agreement dated January 16, 2004, among GMX Resources
                Inc. and the Warrant Holders named therein (Incorporated by
                reference to Current Report on Form 8-K dated January 16, 2004)

  10.10         Registration Rights Agreement dated January 16, 2004, among GMX
                Resources Inc. and the Warrant Holders named therein
                (Incorporated by reference to Current Report on Form 8-K dated
                January 16, 2004)

  10.11         Common Stock Investment Agreement between GMX Resources and the
                Investor named therein (Incorporated by reference to Current
                Report on Form 8-K dated April 5, 2004)

  10.12         Registration Agreement between GMX Resources and the Investor
                named therein (Incorporated by reference to Current Report on
                Form 8-K dated April 5, 2004)

  10.13         Form of Subscription Agreement dated June 23, 2004 between GMX
                Resources, Inc. and Private Placement Investors (Incorporated by
                reference to Exhibit 10.1 to Current Report on Form 8-K dated
                June 18, 2004)

  10.14         Form of Registration Agreement dated June 23, 2004 between GMX
                Resources, Inc. and Private Placement Investors (Incorporated by
                reference to Exhibit 10.2 to Current Report on Form 8-K dated
                June 18, 2004)

  14            Code of Business Conduct and Ethics (Incorporated by reference
                to Exhibit 14 to Annual Report on Form 10-KSB for the year ended
                December 31, 2003)

  21            List of Subsidiaries (Incorporated by reference to Exhibit 21 to
                the Registration Statement on Form SB-2, File No. 333-49328)

  23.1          Consent of KPMG LLP

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

  23.3          Consent of Sproule Associates, Inc.

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

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

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

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

   *  Management contracts or compensatory plan.